All forward-looking statements are expressly qualified in their entirety by the cautionary statements in this section and elsewhere in this report. Other than as required under the applicable securities laws, we do not assume a duty to update these forward-looking statements, whether as a result of new information, subsequent events or circumstances, changes in expectations or otherwise. You should not place undue reliance on these forward-looking statements. All forward-looking statements speak only as of the date of this report or, if earlier, as of the date they were made.

For further information regarding these and other factors, risks and uncertainties affecting us, see Part I, Item 1A. Risk Factors of this report.

Earthstone Energy, Inc., a Delaware corporation ~~(together~~(“Earthstone” and together with our consolidated subsidiaries, the “Company,” “our,” “we,” “us,” ~~“Earthstone”~~ 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, as well as asset and corporate acquisitions and ~~mergers and, to a lesser extent, exploration activities.~~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~~Our primary assets are located in the Midland Basin ~~of west~~in West Texas and the ~~Eagle Ford Trend~~Delaware Basin in New Mexico.

On August 10, 2022, Earthstone, EEH, as buyer, and Titus Oil & Gas Production, LLC, a Delaware limited liability company (“TOGI”), Titus Oil & Gas Corporation, a Delaware corporation, Lenox Minerals, LLC, a Delaware limited liability company, and Lenox Mineral Title Holdings, Inc., a Delaware corporation (collectively, “Titus I”), as seller, consummated the transactions contemplated in that certain Purchase and Sale Agreement dated June 27, 2022, by and among Earthstone, EEH and Titus I (the “Titus I Purchase Agreement”) that was previously reported on Form 8-K filed on June 29, 2022 with the Securities and Exchange Commission (“SEC”). Also on August 10, 2022, Earthstone, EEH, as buyer, and Titus Oil & Gas Production II, LLC, a Delaware limited liability company (“TOGII”), Lenox Minerals II, LLC, a Delaware limited liability company, and Lenox Mineral Holdings II, LLC, a Delaware limited liability company (collectively, “Titus II” and together with Titus I, “Titus”), as seller, consummated the transactions contemplated in that certain Purchase and Sale Agreement dated June 27, 2022, by and among Earthstone, EEH and Titus II (the “Titus II Purchase Agreement,” and together with the Titus I Purchase Agreement, the “Titus Purchase Agreements”) that was previously reported on Form 8-K filed on June 29, 2022 with the SEC. At the closing of the Titus Purchase Agreements, among other things, EEH acquired (the “Titus Acquisition”) interests in oil and gas leases and related property of Titus I and Titus II located in the Delaware Basin, New Mexico, for an aggregate purchase price (the “Titus Purchase Price”) of approximately $567.7 million in cash, which includes approximately $1.1 million in costs directly attributable to the ~~standardized measure~~Titus Acquisition (“Titus Cash Consideration”), net of ~~discounted future~~customary purchase price adjustments, and an aggregate of 3,857,015 shares (the “Titus Shares”) of Class A Common Stock valued at its NYSE closing price on August 10, 2022 of $13.89 per share, net of customary purchase price adjustments. At the closing of the Titus Acquisition, $64.5 million of the Titus Cash Consideration was deposited in an escrow account to support Titus’ indemnity obligations under the Titus Purchase Agreements, 1,811,132 of the Titus Shares were issued to Titus Oil & Gas, LLC, an affiliate of TOGI (“Titus O&G”), and 2,045,883 of the Titus Shares were issued to Titus Oil & Gas Investments II, LLC, an affiliate of TOGII (“Titus O&G II”). On August 10, 2022, in connection with the closing of the Titus Purchase Agreements, Earthstone entered into a customary registration rights agreement with Titus I and Titus II and their respective equity holders

relating to the Titus Shares. On September 2, 2022, a registration statement on Form S-3 with respect to the resale of the Titus shares was filed with the SEC and became automatically effective upon filing.

On July 6, 2022, the 280,000 shares of Series A Convertible Preferred Stock, par value $0.001 per share of Earthstone (the “Series A Convertible Preferred Stock”), automatically converted into 25,225,225 shares of Class A Common Stock. As such, the Series A Convertible Preferred Stock is no longer outstanding and the investors therein were issued the 25,225,225 shares of Class A Common Stock upon the conversion of the Series A Convertible Preferred Stock.

On July 15, 2022, Earthstone filed a certificate of elimination with the Secretary of State of the State of Delaware eliminating all provisions of the certificate of designations previously filed by Earthstone with the Secretary of State of the State of Delaware on April 13, 2022 related to the Series A Convertible Preferred Stock.

On September 29, 2022, in connection with a regularly scheduled borrowing base redetermination, the borrowing base under our Credit Agreement (as defined below) increased from $1.7 billion to $1.85 billion.

On August 10, 2022, Earthstone, EEH, as Borrower, Wells Fargo Bank, National Association (“Wells Fargo”) as Administrative Agent, the lenders party thereto (the “Lenders”) and the guarantors party thereto entered into an amendment (the “Seventh 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, Royal Bank of Canada, as Syndication Agent, Truist Bank, Citizens Bank, N.A., KeyBank National Association, U.S. Bank National Association, Fifth Third Bank, PNC Bank, National Association, and Bank of America, N.A., as Documentation Agents, and the Lenders party thereto (together with all amendments or other modifications, the “Credit Agreement”). Among other things, the Seventh Amendment increased the borrowing base from $1.4 billion to $1.7 billion and increased elected commitments from $800 million to $1.2 billion. The Seventh Amendment also established a fully funded $250 million term loan tranche as a portion of the $1.2 billion of available commitments under the Credit Agreement (the “Term Loan”), with the remaining $950 million of commitments in the form of revolving commitments. The Term Loan is fully pre-payable without premium or penalty, subject to the satisfaction of certain specified conditions, and bears an annual interest rate of Term SOFR (as such term is defined in the Credit Agreement) plus 3.25%, increasing by 0.25% each 180-day period following the Term Loan funding. The Term Loan is co-terminus with the revolving loans' maturity date of June 2, 2027, subject to a potential acceleration of the maturity date to as soon as January 14, 2027 (the “Springing Maturity Date”, as defined in the Credit Agreement) applicable to revolving loans and term loans. The annual interest rate applicable to revolving loans remains a rate of Term SOFR plus an applicable margin between 2.25% and 3.25%, depending upon borrowing base utilization.

On June 2, 2022, the Company, EEH, Wells Fargo, the Lenders and the guarantors party thereto entered into an amendment (the “Sixth Amendment”) to the Credit Agreement. Among other things, the Sixth Amendment extended the maturity of the Credit Agreement to June 2027, increased the borrowing base from $1.325 billion to $1.4 billion and reduced the interest rate for amounts outstanding. Elected commitments under the Credit Agreement remained at $800 million.

On April 14, 2022, in connection with the closing of the Bighorn Acquisition, the Notes Offering and pursuant to the Fifth Amendment, amongst other things, the borrowing base increased to $1,325 million and elected commitments were reduced $800 million compared to the maximum of $1,325 million provided for in the Fifth Amendment in the event that the Bighorn Acquisition had closed prior to the Notes Offering.

On January 30, 2022, Earthstone, EEH as Borrower, Wells Fargo as Administrative Agent, the Lenders and the guarantors party thereto entered into an amended and restated Fifth Amendment (the “Fifth Amendment”) to the Credit Agreement. Among other things, the Fifth Amendment increased the borrowing base and corresponding elected commitments from $650 million to $825 million upon the closing of the Chisholm Agreement.

On April 14, 2022, Earthstone, EEH, as buyer, and Bighorn Asset Company, LLC (“Bighorn”) as seller, consummated the transactions contemplated in the Purchase and Sale Agreement dated January 30, 2022, by and among Earthstone, EEH and Bighorn (the “Bighorn Purchase Agreement”) that was previously reported on Form 8-K filed on February 2, 2022 with the SEC. At the closing of the Bighorn Purchase Agreement, among other things, EEH acquired (the “Bighorn Acquisition”) interests in oil and gas leases and related property of Bighorn located in the Midland Basin, Texas, for a purchase price of approximately $628.2 million in cash, ~~flows~~which includes approximately $2.3 million in ~~Item 2. Properties)~~costs directly attributable to the Bighorn Acquisition, net of customary purchase price adjustments, and 5,650,977 shares (the “Bighorn Shares”) of Class A Common Stock valued at its NYSE closing price on April 14, 2022 of $13.76 per share. At the closing of the Bighorn Acquisition, 510,638 of the Bighorn Shares were deposited in a stock escrow account for Bighorn’s indemnity obligations and 5,140,339 of the Bighorn Shares were issued to Bighorn Permian Resources, LLC, an affiliate of Bighorn (“Bighorn Permian”). On April 14, 2022, in connection with the closing of the Bighorn Purchase Agreement, Earthstone and Bighorn Permian entered into a customary registration rights agreement relating to the Bighorn Shares. On July 15, 2022, a registration statement on Form S-3 with respect to the resale of the Bighorn Shares was filed with the SEC and became automatically effective upon filing.

Also, on April 14, 2022, Earthstone, EnCap Energy Capital Fund XI, L.P. (“EnCap Fund XI”), an affiliate of EnCap Investments L.P. (“EnCap”), and Cypress Investments, LLC (“Cypress” and collectively with EnCap Fund XI, the “Investors”), a fund managed by Post Oak Energy Capital, LP (“Post Oak”), consummated the sale and issuance of 280,000 shares of Series A Convertible Preferred Stock pursuant to that certain Securities Purchase Agreement dated as of January 30, 2022, by and among Earthstone and the Investors (the “SPA”) that was previously reported on Form 8-K filed on February 2, 2022 with the SEC. At the closing of the SPA, Earthstone issued 280,000 shares (the “PIPE Shares”) of Series A Convertible Preferred Stock in exchange for gross cash proceeds of $280 million. Offering costs related to the closing of the SPA were approximately $0.7 million.

On July 6, 2022, all of the PIPE Shares were converted into 25,225,225 shares of Class A Common Stock. The Series A Convertible Preferred Stock is no longer outstanding and the Investors were issued 25,225,225 shares of Class A Common Stock upon the conversion of the Series A Convertible Preferred Stock.

On April 14, 2022, in connection with the closing of the SPA, Earthstone and the Investors entered into a customary registration rights agreement relating to the shares of Class A Common Stock underlying the PIPE Shares. On July 15, 2022, a registration statement on Form S-3 with respect to the resale of the PIPE shares was filed with the SEC and became automatically effective upon filing.

On April 7, 2022, EEH and four of its wholly-owned subsidiaries, Earthstone Operating, LLC, a Texas limited liability company (“Earthstone Operating”), Earthstone Permian LLC, a Texas limited liability company (“Earthstone Permian”), Sabine River Energy, LLC, a Texas limited liability company (“Sabine River Energy”), and Independence Resources Technologies, LLC, a Delaware limited liability company (“Independence Technology” and, together with Earthstone Operating, Earthstone Permian, Sabine River Energy and Earthstone, the “Guarantors”), entered into a purchase agreement (the “Purchase Agreement”) with RBC Capital Markets, LLC, as representative of the several initial purchasers named in the Purchase Agreement (together, the “Initial Purchasers”), providing for the private offer and sale by EEH (the “Notes Offering”) of $550.0 million aggregate principal amount of EEH’s 8.000% senior notes due 2027 (the “Notes”), along with related guarantees (the “Guarantees”) of the Notes.

The Notes Offering closed on April 12, 2022. EEH received net proceeds from the Notes Offering of approximately $537.2 million (after deducting underwriting discounts and commissions) which was used primarily to fund the Bighorn Acquisition and the remainder for general corporate purposes.

On February 15, 2022, Earthstone, EEH, and Chisholm, as seller, consummated the transactions contemplated in the Chisholm Agreement that was previously reported on Form 8-K filed with the SEC on December 17, 2021. At the closing of the Chisholm Agreement, among other things, EEH acquired (the “Chisholm Acquisition”) interests in oil and gas leases and related property of Chisholm located in Lea County and Eddy County, New Mexico, for aggregate consideration, as adjusted for customary purchase price adjustments, consisting of: (i) approximately $314.0 million in cash paid at the closing of the Chisholm Acquisition, (ii) $70 million in cash paid on April 15, 2022, and (iii) 19,417,476 shares of Class A Common Stock valued at its NYSE closing price on February 15, 2022 of $12.85 per share. See further discussion in Note 14. Related Party Transactions in the Notes to Consolidated Financial Statements.

Cash consideration for the Chisholm Acquisition was funded by borrowings under the Credit Agreement.

Inflation has increased costs associated with our capital program and production operations. We have experienced increases in the costs of many of the materials, supplies, equipment and services used in our operations and we expect inflation to continue based on current economic circumstances. In addition, the attempts to reduce inflation by the Federal Reserve have resulted in increased interest rates on debt and contributed to debt and equity market volatility. We continue to closely monitor costs and take all reasonable steps to mitigate the inflationary effect on our cost structure and also work to enhance our efficiency to minimize additional cost increases where possible.

As operator, across the majority of our acreage in the Midland and Delaware Basins, we manage and are able to directly influence development and production ~~of operations~~ of our operated properties. Independent contractors engaged by us provide all the equipment and personnel associated with ~~these~~drilling and completion activities. We employ petroleum engineers, geologists and land professionals who work on improving drilling and completion processes, operating ~~cost,~~costs, 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 on a selective basis.~~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, 2022, our estimated proved oil, natural gas and natural gas liquids reserves were approximately 367,936 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, 2022, our estimated proved reserve quantities were approximately 38% oil, 34% natural gas and 29% natural gas liquids with 72% of those reserves classified as proved developed.

As of December 31, 2022, we had approximately 167,000 net acres in the Midland Basin that are highly contiguous on a project-by-project basis which allow us to drill multi-well pads. Of this acreage, 95% is operated and 5% is non-operated. Approximately 99% of the Midland Basin net acreage is held by production. We hold an approximate 96% working interest in our operated acreage and an approximate 45% working interest in our non-operated acreage. As of December 31, 2022, we had interests in approximately 263 gross / 206 net vertical and 998 gross / 855 net horizontal producing wells, of which we operate 177 vertical and 882 horizontal wells.

During 2022, we completed and began producing from 34 gross / 30.4 net operated wells and 20 gross / 4.1 net non-operated wells.

We are currently operating two drilling rigs in the Midland Basin, both of which are currently drilling in Reagan County, Texas.

As of December 31, 2022, we had approximately 45,000 net acres in the Delaware Basin in New Mexico that are highly contiguous on a project-by-project basis which allow us to drill multi-well pads. Of this acreage, 92% is operated and 8% is non-operated. Approximately 90% of the Delaware Basin net acreage is held by production. We hold an approximate 60% working interest in our operated acreage and an approximate 26% working interest in our non-operated acreage. As of December 31, 2022, we had interests in approximately 265 gross / 94 net vertical and 265 gross / 144 net horizontal producing wells, of which we operate 101 vertical and 159 horizontal wells.

During 2022, we completed and began producing from 25 gross / 18.2 net operated wells and 4 gross / 0.7 net non-operated wells.

We are currently operating three drilling rigs in the Delaware Basin, all of which are currently drilling in Lea County, New Mexico.

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 and Delaware Basins and increase stockholder value through the following:

We believe that the following strengths are beneficial in achieving our business goals:

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.

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, ~~2017,~~2022, three purchasers accounted for ~~18%~~21%, ~~14%~~20% and 14%, respectively, of our revenue during the period. For the year ended December 31, ~~2016,~~2021, two purchasers accounted for ~~41%~~34% and ~~19%~~13%, respectively, of our revenue during the period. For the year ended December 31, ~~2015, one purchaser~~2020, three purchasers accounted for ~~62%~~32%, 15% 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 ~~decided to stop~~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 in our area of operations with well-established markets and numerous purchasers.

During the planning stage of our ~~fields,~~prospective and productive units and acreage, we consider ~~all~~required flow-lines, gathering and delivery ~~infrastructure in the areas of our production.~~infrastructure. Our oil is transported from the wellhead to our tank batteries byor delivery points through our flow-lines or gathering systems. ~~The purchaser~~Purchasers of our oil ~~takes~~take delivery ~~of the oil~~(i) at ~~the~~a pipeline delivery point or (ii) at our tank batteries ~~and transports the oil~~for transport by ~~truck on a frequent interval, from which point it is transported by various modes by the purchaser to the eventual refining facility.~~truck. 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 ~~move the majority of~~install vapor recovery units in our newly installed tank batteries which also reduces emissions.

Our produced salt water is generally moved by pipeline connected to our operated ~~salt water~~saltwater disposal wells ~~rather as wells as~~or by ~~truck~~pipeline to commercial disposal facilities.

Consistent with our disciplined approach to financial management, we have an active commodity hedging program through which we seek to hedge a ~~final disposal destination.~~

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.

The domestic oil and natural gas industry is intensely competitive in the ~~exploration for~~acquisition of acreage, production and ~~acquisition of~~oil and gas reserves and in ~~the~~ producing, transporting and marketing ~~of its production.~~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 prospective 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.

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. ~~We consider drilling rig services ancillary to our oil and natural gas exploration and producing activities and manage these services to support such activities.~~ All of our operations are currently conducted in ~~Texas.~~

Texas and New Mexico.

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.

Our ability to market oil and natural gas found and produced, ~~if any, will depend~~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 ~~our marketing professionals~~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~~significant amounts of 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. Specifically, increased foreign production and increased efficiencies in horizontal drilling, combined with exploration of newly developed 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,~~natural gas liquids, we are unable to accurately predict future oil, natural gas and ~~NGLs~~natural gas liquids 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.

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:

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.

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. Moreover, the current administration has indicated that it expects to impose additional federal regulations limiting access to and production from federal lands. 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. 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, including New Mexico, 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 negatively 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.

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.

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 ~~law and to~~ 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.

Our operations are also subject to stringent federal, state and local laws regulating the discharge and emission 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.

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 or threatened 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, or transported, 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. Although CERCLA generally exempts “petroleum” from the definition of hazardous substance, in the course of our operations, we have generated and will generate wastes that may fall within CERCLA’s definition of hazardous substance and may have disposed of these wastes at disposal sites owned and operated by others. Comparable state statutes may not provide a comparable exemption for petroleum. Moreover, the EPA has begun to utilize CERCLA to further its “environmental justice” goals by focusing enforcement of cleanup efforts in underserved and overburdened areas. The EPA defines environmental justice as “the fair treatment and meaningful involvement of all people regardless of race, color, national origin, or income, with respect to the development, implementation, and enforcement of environmental laws, regulations, and policies.” We are able to control directly the operation of only those wells ~~with respect to~~for 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. For example, in response to a lawsuit filed in the U.S. District Court for the District of Columbia by several non-governmental environmental groups against the EPA for the agency’s failure to timely assess its RCRA Subtitle D criteria regulations for oil and natural gas wastes, the EPA and the environmental groups entered into an agreement that was finalized in a consent decree issued by the District Court on December 28, 2016. Under the decree, the EPA is required to propose no later than March 15, 2019, a rulemaking for revision of certain Subtitle D criteria regulations pertaining to oil and natural gas wastes or sign a determination that revision of the regulations is not necessary. If the EPA proposes a rulemaking for revised oil and natural gas waste regulations, the consent decree requires that the EPA take final action following notice and comment rulemaking no later than July 15, 2021. 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.

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, a new~~January 2023, the EPA and ~~U.S. Army~~the Corps ~~of Engineers~~issued a final rule defining the scope of federal jurisdiction over wetlands and other waters became effective. To the extent the rule expands the range of properties subject to the Clean Water Act’s jurisdiction, certain energy companies could face increased costs and delays with respect to obtaining permits for dredge and fill activities in wetland areas. The rule has been challenged in court on the grounds that it unlawfully expands the reach of Clean Water Act programs, and implementation of the rule has been stayed pending resolution of the court challenge. In addition, following the issuance of a presidential executive order to review the rule, on July 27, 2017, the EPA proposed to repeal the rule and also separately announced its intent to conduct a substantive re-evaluation ofrevises the definition of “waters of the United States” ~~in a future rulemaking.~~. The final rule has been challenged by several states and industry groups. As a result ~~future implementation~~ of these developments, the ~~rule~~scope of federal jurisdiction under the Clean Water Act is uncertain at this time.

The process for obtaining permits has the potential to delay our ~~operations.~~operations, and any expansion of permitting jurisdiction over wetlands or streams could result in further delays and additional operating costs. 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 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 ~~at depths~~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, the EPA previously announced plans to develop a Notice of Proposed Rulemaking by June 2018, which would describe a proposed mechanism, regulatory, voluntary, or a combination of both, to collect data on hydraulic fracturing chemical substances and mixtures. Also, 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.

In addition, on March 26, 2015, the Bureau of Land Management (the “BLM”) published a final rule governing hydraulic fracturing on federal and Indian lands. Also, on November 15, 2016, the BLM finalized a rule to reduce the flaring, venting and leaking of methane from oil and natural gas operations on federal and Indian lands. On March 28, 2017, President Trump signed an executive order directing the BLM to review the above rules and, if appropriate, to initiate a rulemaking to rescind or revise them. Accordingly, on December 29, 2017, the BLM published a final rule to rescind the 2015 hydraulic fracturing rule. Also, on December 8, 2017, the BLM published a final rule to suspend or delay certain requirements of the 2016 methane rule until January 17, 2019. Further legal challenges are expected. At this time, it is uncertain when, or if, the rules will be implemented or modified, and what impact they would have on our operations.

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.

~~Some~~

Several states, ~~and local jurisdictions in which we operate or hold oil and natural gas interests~~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. Additionally, New Mexico has adopted regulations that require the disclosure of information regarding the substances used in the hydraulic fracturing process. 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.

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.

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 strict and 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 ~~Clean Air Act~~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~~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, ~~President~~the Trump Administration directed the EPA to review the 2016 regulations and, if appropriate, to initiate a ~~rulemaking~~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. ~~On June 16, 2017,~~In September 2020, the EPA ~~published~~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. In November 2021, the EPA proposed new source performance standards and emissions guidelines to reduce methane and other pollution from new and existing sources in the oil and gas industry. The proposed rule would include, among other things, a comprehensive monitoring program for new and existing well sites, zero-emissions standards for new and existing pneumatic controls, and standards to ~~stay~~eliminate venting of associated gas and requirements for ~~two years certain~~the capture and sale of natural gas where a sales line is available. If adopted, these requirements could increase our costs to operate and control pollution. In November 2022, the EPA issued a Supplemental Proposal regarding the proposed new source performance standards and emissions guidelines for reducing methane and VOCs in the oil and natural gas sector. The Supplemental Proposal expands the November 2021 proposal to include more comprehensive requirements to reduce emissions, including application of methane monitoring obligations to wellhead-only sites and well sites with low emissions. It also would create a new third-party monitoring program to flag large emissions events known as the ~~2016~~“Super-Emitter Response Program.” The EPA expects to finalize its new methane rules in 2023. The foregoing laws, regulations, ~~including fugitive emission requirements. These~~and 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. WeUntil these rules are formally adopted, we cannot predict the final regulatory requirements or the cost to comply with such requirements with any certainty.

On August 16, 2022, President Biden signed the Inflation Reduction Act of 2022 (“IRA”). The IRA allocated $1.55 billion to the Methane Emissions and Waste Reduction Incentive Program. The IRA also required the EPA to implement a waste emission charge on methane emitted from applicable oil and gas facilities that exceed certain thresholds. The methane charge goes into effect in 2024 at $900 per metric ton of methane and increases to $1,500 per metric ton of methane by 2026. The charge will act as an incentive for operators to reduce emissions by minimizing leaks and replacing equipment rather than paying for excessive emissions.

In November 2022, the Department of the Interior announced a proposed rule from the Bureau of Land Management (“BLM”) that would impose additional requirements on oil and natural gas production on federal and Tribal lands, including the use of “low bleed” pneumatic equipment and vapor recovery for oil storage tanks, implementation of leak detection plans, implementation of waste minimization plans, and monthly limits on royalty-free flaring. If adopted, these rules could adversely affect our production of oil and gas pursuant to federal leases in New Mexico.

In October 2015, the EPA announced that it was lowering the primary ~~national ambient air quality standards~~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. In mid-2022, the Biden Administration announced that it was considering designating the Permian Basin in Texas as a “non-attainment zone,” which, if designated, would result in increased permitting and compliance requirements for drilling operations in the state to decrease ozone levels. The Biden Administration has since omitted the potential designation from an agenda of planned regulations, indicating that it is not expected to be finalized in the next year. The EPA, ~~did not meet an October 2017 deadline for designating non-attainment areas but has indicated that it continues to work with states to make~~however, could revive the ~~required designations. If implemented~~effort in the ~~future,~~future. In 2022, the ~~changes will take place over several years; however,~~New Mexico Environment Department (“NMED”) adopted “ozone precursor rules.” The ozone precursor rules went into effect on August 5, 2022 and apply to oil and gas sources in New Mexico that would cause or contribute to ambient ozone concentrations that exceed 95% of the ~~new standard could result~~NAAQs for ozone. As of the effective date, these rules apply to oil and natural gas production in ~~a significant expansion~~the following counties in New Mexico: Chaves, Dona Ana, Eddy, Lea, Rio Arriba, Sandoval, San Juan, and Valencia. The rules apply to certain crude oil and natural gas production and processing equipment associated with operations. Reclassification of ~~ozone non-attainment~~ areas ~~across the United States, including~~of state implementation of NAAQS, or designation of areas in which we ~~operate. Oil~~operate as non-attainment zones, 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.

Moreover, the NMOCD recently adopted new rules, which require oil and gas operators to capture 98 percent of their methane waste by the end of 2026. The new rules went into effect on May 25, 2021. 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 ~~ozone non-attainment areas~~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 August 2022, for example, the EPA announced that it would ~~likely~~ be ~~subject~~conducting helicopter flyovers of the Permian Basin region in New Mexico and Texas. The flyovers used infrared cameras to survey oil and gas operations to identify large emitters of methane and VOCs. Based on data obtained during flyovers, EPA intends to initiate enforcement follow up actions with facilities operators. In addition, the RRC has increased ~~regulatory burdens~~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 ~~form of more stringent emission controls, emission offset requirements, and increased permitting delays and costs.~~

future.

In ~~December 2009, the EPA issued an Endangerment Finding that determined~~response to findings that emissions of carbon dioxide, methane and other ~~greenhouse gases (“GHGs”), present an endangerment to~~GHGs endanger public health and the environment, ~~because, according to~~ the EPA ~~emissions of such gases contribute to warming~~has adopted regulations under existing provisions of the ~~earth’s atmosphere~~CAA that, among other things, establish construction and other climatic changes. In May 2010, the EPA adopted regulations establishing new GHG emissions thresholds that determine when stationary sources must obtain permits under the Prevention of Significant Deterioration, or PSD, and Title V programs of the Clean Air Act. On June 23, 2014, in ~~Utility Air Regulatory Group v. EPA~~, the Supreme Court held that stationary sources could not become subject to PSD or Title V permitting solely by reason of their GHG emissions. The Court ruled, however, that the EPA may require installation of best available control technology

operating permit reviews for GHG emissions atcertain large stationary sources, ~~otherwise subject to~~require the ~~PSD~~monitoring and ~~Title V programs. On August 26, 2016,~~annual reporting of GHG emissions from certain petroleum and natural gas system sources in the ~~EPA proposed changes needed to bring EPA’s air permitting regulations~~United States, implement New Source Performance Standards directing the reduction of methane from certain new, modified, or reconstructed facilities in ~~line~~the oil and natural gas sector, and together with the ~~Supreme Court’s decision~~Department of Transportation (the “DOT”), implement GHG emissions limits on ~~GHG permitting. The proposed rule was published~~vehicles manufactured for operation in the ~~Federal Register on October 3, 2016~~United States. Additionally, various states and ~~the public comment period closed on December 2, 2016.~~

~~In addition, the U.S. Congress has from time to time considered~~groups of states have adopted or are considering adopting legislation, to reduce emissions of greenhouse gases and almost one-half of the states have already taken legal measures to reduce emissions of greenhouse gases primarily through the planned development of greenhouse gas emission inventories and/regulations or ~~regional greenhouse gas~~other regulatory initiatives that are focused on such areas as GHG cap and trade ~~programs. Although~~programs, carbon taxes, reporting and tracking programs, and restriction of emissions. At the ~~U.S. Congress has not adopted such legislation at this time, it may do so~~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.The United States rejoined the Paris Agreement in February 2021. In early 2021, the ~~future~~Biden Administration issued a moratorium on oil and ~~many states continue to pursue regulations~~gas leasing on federal lands and waters to reduce ~~greenhouse gas~~ emissions.

Since then, the moratorium has been the subject of litigation and, in August 2022, a federal judge entered an injunction against the moratorium. In ~~December 2015,~~November 2021, the United States participated in the ~~21st~~United Nations Climate Change Conference in Glasgow, Scotland, United Kingdom (“COP26”). COP26 resulted in a pact among approximately 200 countries, including the United States, called the Glasgow Climate Pact. Relatedly, the United States and European Union jointly announced the launch of the ~~Parties~~“Global Methane Pledge,” which aims to cut global methane pollution at least 30% by 2030 relative to 2020 levels, including “all feasible reductions” in the energy sector. In conjunction with COP26, the United States committed to an economy-wide target of reducing net greenhouse gas emissions by 50-52 percent below 2005 levels by 2030. Also in November 2021, President Biden signed a $1 trillion dollar infrastructure bill into law. The new infrastructure law includes several climate-focused investments, including upgrades to power grids to accommodate increased use of renewable energy and expansion of electric vehicle infrastructure. The above-referenced IRA allocated $369 billion to energy and climate initiatives. In November 2022, the United States participated in the United Nations ~~Framework Convention on~~ Climate Change Conference in Paris, France. The resulting Paris Agreement calls for the parties to undertake “ambitious efforts” to limit the average global temperature, and to conserve and enhance sinks and reservoirs of GHGs. The Agreement went into effect on November 4, 2016. The Agreement establishes a framework for the parties to cooperate and report actions to reduce GHG emissions. However, on June 1, 2017, President Trump announced that the United States would withdraw from the Paris Agreement, and begin negotiations to either re-enter or negotiate an entirely new agreement with more favorable terms for the United States. The Paris Agreement sets forth a specific exit process, whereby a party may not provide notice of its withdrawal until three years from the effective date, with such withdrawal taking effect one year from such notice. It is not clear what steps the Trump Administration plans to take to withdraw from the Paris Agreement, whether a new agreement can be negotiated, or what terms would be included in such an agreement. Furthermore, in response to the announcement, many state and local leaders have stated their intent to intensify efforts to uphold the commitments set forth in the international accord.

Restrictions on emissions of methane or carbon dioxide that may be imposed could adversely impact the demand for, price of and value of our products and reserves. As our operations also emit greenhouse gases directly, current and future laws or regulations limiting such emissions could increase our own costs. Currently, our operations are not adversely impacted by existing federal, state and local climate change initiatives and, at this time,Egypt (“COP27”). Although it is not possible at this time to ~~accurately estimate~~predict what additional domestic legislation may be adopted in light of the Paris Agreement or the Glasgow Climate Pact, or how ~~potential future laws~~legislation or new regulations ~~addressing greenhouse gas~~that may be adopted based on the Paris Agreement or the Glasgow Climate Pact to address GHG emissions would impact our ~~business.~~

~~National Environmental Policy Act~~

~~Oil~~business, any such future laws and regulations imposing reporting obligations on, limiting emissions of GHGs from our equipment and operations, or restricting federal leases could impair our production, could require us to incur costs to reduce emissions of GHGs associated with our operations, and could decrease demand for oil and natural gas.

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. For example, the New Mexico Environment Department has adopted regulations to restrict the venting or flaring of methane from both upstream and midstream 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 ~~development~~ and production ~~activities on~~companies in state or federal ~~lands~~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 ~~subject to~~responsible for roadway and infrastructure damages, or alleging that the ~~National Environmental Policy Act (“NEPA”). NEPA requires federal agencies, including the Department~~companies have been aware of the ~~Interior,~~adverse effects of climate change for some time but defrauded their investors by failing to ~~evaluate major agency actions that have~~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. In early 2023, for example, legislators in New Mexico introduced a bill that, if enacted, would significantly ~~impact~~revise the ~~environment. The process involves~~state’s 1935 Oil & Gas Act by, among other things, removing the ~~preparation of either~~$250,000 cap on “blanket bonds” that oil and gas operators put up as financial assurance to plug and clean wells, establishing setbacks for oil and gas operations near certain communities, and establishing an environmental assessment or environmental impact statement depending on whether the specific circumstances surrounding the proposed federal action will have a significant impact on the human environment. The NEPA process involves public input through comments which can alter the nature of a proposed project either by limiting the scope of the project or requiring resource-specific mitigation. NEPA decisions can be appealed through the court system by process participants. This processjustice advisory council. Additionally, political, litigation and financial risks may result in ~~delaying~~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. We also are aware that the ~~permitting~~SEC intends to propose new and ~~development~~additional rules regarding company disclosure of ~~projects, increase the costs of permitting~~climate change risk. We will monitor and ~~developing some facilities and could result in certain instances in the cancellation of existing leases.~~

comply with any such promulgated rules.

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. ~~On February 11, 2016,~~As a result of a 2011 settlement agreement, the ~~U.S. Fish and Wildlife Service published a final policy which alters how it identifies critical habitat~~FWS was required to determine whether to identify more than 250 species as endangered or threatened under the ESA 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 ~~endangered and threatened species.~~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 ~~Migratory Bird Treaty Act.~~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 ~~Migratory Bird Treaty Act,~~MBTA, and we are not aware of any proposed ESA listings that will materially affect our operations. Nevertheless, we are monitoring listings and proposed listings by the FWS to ensure continued compliance. In November 2022, FWS listed the southern distinct population segments of the lesser prairie-chicken that occupy habitats in eastern New Mexico and the southwest Texas Panhandle. In January 2023, FWS listed the Sacramento Mountains checkerspot butterfly in New Mexico. The federal government in the past has issued indictments under the ~~Migratory Bird Treaty Act~~MBTA to several oil and natural gas companies after dead migratory birds were found near reserve pits associated with drilling activities. In January 2020, a new U.S. Department of the Interior (“DOI”) rule went into effect clarifying that only the intentional taking of protected migratory birds is subject to prosecution under the MTBA. In December 2021, however, that rule was revoked, and a new rule took effect reinstating the prohibition on incidental takes 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.

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.

We are subject to ~~the requirements~~a number of ~~the~~ federal ~~Occupational Safety~~ and ~~Health Act, as amended (“OSHA”),~~state laws and regulations, including OSHA, and comparable state statutes that regulate the protection of the health and safety of workers. 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.

Texas ~~regulates~~and New Mexico regulate the drilling for, and the production, gathering and sale of, oil and natural gas, including imposing severance taxes and requirements for obtaining drilling permits. Texas and New Mexico currently ~~imposes~~impose a ~~4.6%~~ severance tax on oil production of 4.6% and 3.75%, respectively, and a ~~7.5%~~ severance tax on natural gas ~~production.~~and natural gas liquid production of 7.5% and 3.75%, respectively. 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~~allowable 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.

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 ~~2017,~~2022, nor do we anticipate that such expenditures will be material in ~~2018.~~

2023.

As of December 31, ~~2017,~~2022, we had 58219 full-time employees, of which ~~nine~~13 are management, 1962 are technical personnel, 1637 are administrative personnel and 14107 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.

~~Office Leases~~

The health, safety and wellbeing of our employees, contractors, and everyone impacted by our operations is of paramount importance to all of us at Earthstone. We ~~lease office space~~believe that it is our responsibility to employ best practices for safety procedures and provide a safe workplace, as ~~set forth~~well as strive to ensure that each and every one of our employees and contractors understands the importance of the role each plays in maintaining a safe work environment. Through leadership and commitment to training, safety has become imbedded in our culture and is a critical component of our success.

Our contractors and vendors are held to the same high safety standards that we require of employees. As part of this mandate, we monitor these partners to make certain that proper procedures are maintained and that contractors comply with regulatory requirements and guidelines.

In response to the emergence of the COVID-19 pandemic, we continue to monitor and take seriously the guidelines of health experts and are adhering to the highest possible standards issued by the World Health Organization (“WHO”) and Centers for Disease Control (“CDC”) as well as governments and regulators across our areas of operations. We have implemented a number of measures to safeguard the health of our employees, contractors and the community, while continuing to operate responsibly and maintaining the resiliency of the Company.

Our focus on health and safety is demonstrated by zero employee lost time incidents due to injuries at the workplace in each of 2020, 2021 and 2022.

At Earthstone, we know that our people drive our success, and we are committed to providing a rewarding and productive work environment and a culture of respect for our employees. We believe in fostering an inclusive culture to ensure the strength and resilience of our business. Our Code of Ethics, which applies to our directors, officers and employees when they are acting on our behalf, reinforces our long-standing commitment to high ethical standards and summarizes the fundamental importance of acting with integrity. We value the perspectives, experiences and ideas contributed by all employees and pledge to foster their professional growth by embracing the following principles:

Our success is based on financial performance and operational results, and we believe that our compensation program is an important driver of that success. The primary objectives of our compensation program are to pay for performance, encourage long-term shareholder value, encourage profitable growth in our oil and natural gas reserves and production, encourage growth in cash flow and profitability, survive and preserve value and upside potential for shareholders during industry and economic downturns, and mitigate risks in our business related to compensation by balancing fixed compensation with short-term and long-term performance-based incentive compensation. Further, we operate in a highly competitive and challenging environment and must retain, attract and motivate talented individuals with the requisite technical and managerial skills to successfully pursue our business strategy. To accomplish this, our compensation program is designed to reward employees for their performance and motivate them to continue to perform at a high level through both absolute and relative performance assessment.

We provide our employees with a comprehensive compensation program. We provide a competitive base salary as a fixed component of our compensation program. The annual cash payment is our short-term incentive for eligible employees, which reinforces both corporate and individual annual performance and prioritizes both financial and operational metrics. Eligible employees may also receive long-term incentives in the ~~following table:~~

~~Location~~	~~Approximate Size~~	~~Lease Expiration Date~~	~~Intended Use~~
~~The Woodlands, Texas~~	~~19,600 sq. ft.~~	~~December 31, 2019~~	~~Office~~
~~Midland, Texas~~	~~9,200 sq. ft.~~	~~June 30, 2019~~	~~Office~~
~~Denver, Colorado~~ ⁽¹⁾	~~7,000 sq. ft.~~	~~April 30, 2018~~	~~Office~~

form of restricted stock unit awards and performance restricted stock unit awards that vest over multiple years to support retention and align employee interests with those of our stockholders, by driving value at the enterprise level. We provide market-competitive pay levels to attract and retain the highly qualified talent. We regularly benchmark each component of our compensation program to ensure we remain competitive. All employees may participate in our 401(k) Retirement Savings Plan.

~~(1)~~

~~In June 2017, management announced that the office located in Denver, Colorado, will be closing upon the end of its lease term, which is April 30, 2018.~~

Office Locations

~~During 2017, aggregate rental payments for~~

Our corporate headquarters are located at 1400 Woodloch Forest Drive, the Woodlands, Texas, with additional offices located at 600 North Marienfeld Street, Midland, Texas and 5301 Knickerbocker Road, San Angelo, Texas.

Information about our ~~office facilities totaled approximately $0.9 million.~~

Executive Officers ~~of the Company~~

The following table sets forth, as of March 1, ~~2018,~~2023, certain information regarding the executive officers of Earthstone:

~~Name~~

~~Age~~

~~Position~~

Name

Age

Position

Frank AA. Lodzinski

73

68

Executive Chairman of the Board

Robert J. Anderson

61

President and Chief Executive Officer

~~Robert J. Anderson~~

56

~~Executive Vice President, Corporate Development and Engineering~~

Tony Oviedo

69

64

Executive Vice President, Accounting and Administration

Mark Lumpkin, Jr.

49

44

Executive Vice President and Chief Financial Officer

Steven C. Collins

58

53

Executive Vice President, ~~Completions and Operations~~

Chief Operating Officer

Timothy D. Merrifield

67

62

Executive Vice President, Geological and Geophysical

~~Francis M. Mury~~

Robert W. Hunt, Jr

42

66

Executive Vice President, ~~Drilling and Development~~

General Counsel

~~Ray Singleton~~

66

~~Director and Executive Vice President~~

The following biographies describe the business experience of our executive officers:

Frank A. Lodzinskihas over 50 years of oil and gas industry experience and served as our Chairman ~~President~~since December 2014 and as Executive Chairman since April 1, 2020. He served as our Chief Executive Officer ~~since~~from December ~~2014.~~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 ~~OVR~~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 ~~OVR,~~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 ~~OVR. He has over 45 years of oil and gas industry experience. In~~Oak Valley. From 1984 to 2004, 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~~and/or managed several entities that were ~~exchanged~~ultimately sold or merged into larger companies or were otherwise monetized for ~~common shares~~the benefit 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.shareholders. In 2004, Mr. Lodzinski formed Southern Bay Energy, LLC ~~the general partner of~~(“Southern Bay”) and served as its President. Through an affiliated limited partnership, Southern Bay ~~Oil & Gas, L.P., which~~ acquired ~~the residual assets of AROC, Inc.,~~oil and ~~he served as President of Southern Bay Energy, LLC upon its formation.~~gas assets. The Southern Bay entities were merged into GeoResources in April 2007. Mr. Lodzinski ~~has~~ served as a

26

director and member of ~~the compensation committee~~various board committees of Yuma Energy, Inc. ~~since October 2016 and previously served on its audit committee~~(“Yuma”) from September 2014 to October ~~2016. He~~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 April 15, 2020 and on October 19, 2020 the cases were converted to a Chapter 7 liquidation. In connection therewith, Mr. Lodzinski resigned from Yuma’s board of directors. Mr. Lodzinski holds a BSBA degree in Accounting and Finance from Wayne State University in Detroit, ~~Michigan~~.

Michigan.

Robert J. Anderson is has served as a ~~petroleum engineer with over 30 years of diversified domestic~~director since July 2021. He has served as our President and ~~international oil and gas experience. He has~~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 since December 2014.~~Engineering. Previously, he served in a similar capacity with ~~OVR~~Oak Valley from March 2013 until the closing of its strategic combination with ~~Earthstone~~the Company in December 2014. Prior to joining ~~OVR,~~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. ~~From September 2000~~Prior to ~~February~~March 2004, he was employed byin technical and supervisory roles with Anadarko Petroleum Corporation, ~~as a petroleum engineer. In addition, he has worked with~~ major oil companies including ARCO International/Vastar Resources, and independent oil companies, including Hugoton Energy, Hunt Oil ~~Hugoton Energy,~~ 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. His domestic acquisition and divestiture experience includes Texas and Louisiana (offshore and onshore), Mid-Continent, and the Rocky Mountain states, and his international experience includes Canada, South America, and Russia. Mr. Anderson has a B.S. degree in Petroleum Engineering from the University of Wyoming and an MBA from the University of Denver.

Tony Oviedohas served as our Executive Vice President –- Accounting and Administration (Principal Accounting Officer) since February 10, 2017. Mr. Oviedo has over 3041 years of professional experience with both private and public companies. Prior to joining ~~Earthstone,~~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 2027 years of experience including over 1318 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,~~the Company, 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.

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. Information filed with the SEC may be read or copied at the SEC’s Public Reference Room at 100 F Street, N.E., Washington, D.C. 20549. Information on operation of the Public Reference Room may be obtained by calling the SEC at 1-800-SEC-0330 (1-800-732-0330). The SEC ~~also~~ 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.

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~~Readers 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.

We

The following is a summary of the material risks and uncertainties we have identified, which should be read in conjunction with the more detailed description of each risk factor contained below.

The prices we receive for our oil, natural gas and natural gas ~~liquids~~liquid 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~~liquid has been volatile. For example, during the period from January 1, ~~2014~~2020 through December 31, ~~2017,~~2022, the ~~West Texas Intermediate (“WTI”) futures~~WTI spot price for oil ~~declined~~ranged from -$36.98 per Bbl in April 2020 to $123.64 in June 2022. The Henry Hub spot price for natural gas ranged from a low of $1.33 per MMBtu in September 2020 to a high of ~~$107.26~~$9.85 per ~~Bbl on June 20, 2014~~MMBtu in September 2022. During 2022, WTI spot prices ranged from $71.05 to ~~$26.21~~$123.64 per Bbl ~~on February 11, 2016, and subsequently increased to reach a high of $60.01 per Bbl in December 2017;~~ and the Henry Hub ~~futures~~spot price ~~for~~of natural gas ~~has declined~~ranged from ~~a high of $6.15~~$3.46 to $9.85 per ~~MMBtu on February 19, 2014 to a low of $1.64 per MMBtu on March 3, 2016, and subsequently increased to reach a high of $3.69 per MMBtu in December 2017.~~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~~liquid we produce and our production levels depend on numerous factors beyond our control, including:

Lower oil, natural gas and natural gas ~~liquids~~liquid 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. Under the EEH Credit Agreement, our borrowing base is subject to semi-annual redeterminations (May 1 and November 1) and our lenders have the right to call for an interim determination of the borrowing base under certain circumstances. A sustained decline in oil, natural gas and natural gas ~~liquids~~liquid prices could adversely impact our borrowing base in future borrowing base redeterminations, which could trigger repayment obligations under the ~~EEH~~ 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~~liquid prices may typically cause a decline in the market price of our shares.

~~As a result of low~~

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 ~~have been required to, and~~ 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.

Availability under the ~~EEH~~ Credit Agreement is ~~currently~~ subject to athe lesser of elected commitments and the borrowing base ~~of $185.0 million.~~then in effect. The borrowing base is subject to scheduled semiannual redeterminations ~~(May~~(on or about May 1 and November 1), as well as other ~~elective~~lender-elective borrowing base redeterminations. The lenders can unilaterally adjust the borrowing base, ~~and the~~which impacts available borrowings permitted to be outstanding under the ~~EEH~~ Credit ~~Agreement.~~Agreement to the degree that the borrowing base is lower than the elected commitments. Reductions in estimates of our oil, natural gas and natural gas ~~liquids~~liquid reserves may result in a reduction in our borrowing base under the ~~EEH~~ Credit Agreement (if prices are kept constant). Reductions in our borrowing base under the ~~EEH~~ Credit Agreement could also arise from other factors, including but not limited to:

Our borrowings under our Credit Agreement make us vulnerable to increases in interest rates as they bear interest at a rate elected by us that is based on the prime, SOFR or federal funds rate plus margins ranging from 1.25% to 3.25%, depending on the rate used and the amount of the loan outstanding in relation to the elected commitment.

Our debt agreements, including our Credit Agreement and the indenture governing the Notes (the “Indenture”), contain restrictive covenants that limit our ability to engage in activities that may be in our long-term best interests, including restrictions on incurring debt, issuing dividends, repurchasing Class A Common Stock, selling assets, creating liens, entering into transactions with affiliates, and merging, consolidating, or selling our assets. Our ability to borrow under our Credit Agreement is subject to compliance with certain financial covenants. See Note 12. Long-Term Debt in the Notes to Consolidated Financial Statements. These restrictions on our ability to operate our business could significantly harm us by, among other things, limiting our ability to take advantage of financings, mergers and acquisitions, and other corporate opportunities.

Our failure to comply with these covenants could result in an event of default that, if not cured or waived, could result in the acceleration of all or a portion of our indebtedness. We do not have sufficient working capital to satisfy our debt obligations in the event of an acceleration of all or a significant portion of our outstanding indebtedness.

Beginning in the second half of 2021 and continuing throughout 2022, we, similar to other companies in our industry, experienced inflationary pressures on our operating costs and capital expenditures - namely the costs of fuel, steel (i.e., wellbore tubulars), labor and drilling and completion services. Such inflationary pressures on our operating and capital costs, which we currently expect to continue in 2023, have negatively impacted our operating margins, cash flows and results of operations. We have undertaken, and plan to continue with, certain initiatives and actions (such as agreements with service providers to secure the costs and availability of services) to mitigate such inflationary pressures. However, there can be no assurance that such efforts will offset, largely or at all, the impacts of any future inflationary pressures on our operating costs and capital expenditures and, in turn, our cash flows and results of operations.

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.

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~~liquid 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.

At December 31, ~~2017,~~2022, approximately ~~75%~~28% of our estimated proved reserves were classified as proved undeveloped. The development of our estimated proved undeveloped reserves of ~~60,015 MBOE~~103,215 MBoe will require an estimated ~~$665.9~~$1,200.6 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 ~~EEH~~ 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 applicable 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~~Where 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,~~regulations the actual capital expenditures may vary from estimated capital expenditures, development may not occur as scheduled and actual results may ~~not~~ be asless than estimated.

A reader 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, ~~2017, 2016~~2022, 2021 and ~~2015,~~2020, 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.~~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 our oil and natural ~~gas;~~

gas production; 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.~~uncertain and include properties with which we do not have a long operational history. 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 or other conditions down-hole, 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.~~property and any indemnities we do obtain may be subject to temporal and monetary limitations. 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 or incur unforeseen liabilities, which could adversely affect our business, financial condition and results of operations.

33

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~~liquid 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. Because of these uncertain factors, we do not know if the drilling locations we have identified will ever be drilled or if we will be able to produce oil or natural gas from these or any other drilling locations. 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 placed on 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 well 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, frac crews, water, 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, frac crews, water, 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 ~~2018~~2023 capital expenditures with cash on hand, cash generated by operations, borrowings under the ~~EEH~~ 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

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other services and equipment and regulatory, technological and competitive developments. A significant 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 ~~EEH~~ Credit Agreement.

If our revenues or the borrowing base under the ~~EEH~~ 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 stakeholder sentiment towards the oil and natural gas industry and increased attention to ESG and conservation matters may adversely impact our business.

Increasing attention to climate change and environmental matters, societal expectations on companies to address climate change, investor and societal expectations regarding voluntary ESG initiatives and disclosures, and consumer demand for alternative sources of energy may result in increased costs (including but not limited to increased costs associated with financing activities, compliance, stakeholder engagement, contracting, and insurance), reduced demand for our products, reduced profits, increased legislative and judicial scrutiny, investigations and litigation, and negative impacts on our stock price and access to capital markets. Increasing attention to climate change and environmental conservation, for example, may result in demand shifts for oil and natural gas products and additional governmental investigations and private litigation against us. To the extent that societal pressures or political or other factors are involved, it is possible that liability could be imposed on us without regard to our causation of or contribution to the asserted damage, or to other mitigating factors. Voluntary disclosures regarding ESG matters, as well as any ESG disclosures mandated by law, could result in private litigation or government investigation or enforcement action regarding the sufficiency or validity of such disclosures. In addition, failure or a perception (whether or not valid) of failure to implement ESG strategies or achieve ESG goals or commitments, including any GHG reduction or neutralization goals or commitments, could result in governmental investigations or enforcement, private litigation and damage our reputation, cause our investors or consumers to lose confidence in our Company, and negatively impact our operations.

Moreover, while we may create and publish voluntary disclosures regarding ESG matters from time to time, many of the statements in those voluntary disclosures may be on hypothetical expectations and assumptions that may or may not be representative of current or actual risks or events or forecasts of expected risks or events, including the costs associated therewith. Such expectations and assumptions are necessarily uncertain and may be prone to error or subject to misinterpretation given the long timelines involved and the lack of an established single approach to identifying and measuring many ESG matters. Such disclosures may also be partially reliant on third-party information that we have not or cannot independently verify. Additionally, we expect there will likely be increasing levels of regulation, disclosure-related and otherwise, with respect to ESG matters, and increased regulation will likely lead to increased compliance costs as well as scrutiny that could heighten all of the risks identified in this risk factor.

In addition, organizations that provide information to investors on corporate governance and related matters have developed ratings processes for evaluating companies on their approach to ESG matters. Such ratings are used by some investors to inform their investment and voting decisions. Unfavorable ESG ratings and recent activism directed at shifting funding away from companies with energy-related assets could lead to increased negative investor sentiment toward us and our industry and to the diversion of investment to other industries, which could have a negative impact on our stock price and our access to and costs of capital. Also, institutional lenders may, of their own accord, decide not to provide funding for fossil fuel energy companies based on climate change, environmental matters, or other ESG related concerns, which could affect our access to capital for potential growth projects. Moreover, to the extent ESG matters negatively impact our or the fossil fuel industry’s reputation, we may not be able to compete as effectively to recruit or retain employees, which may adversely affect our operations.

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 fixed price swaps, basis swaps, costless collars ~~puts~~ and ~~basis swaps.~~deferred premium put options. 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.~~earnings, which may result

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in significant noncash gains or losses. 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.~~instruments, especially during periods of oil and natural gas price increases. 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~~Management’s Discussion and Analysis of Financial Condition and Results of Operations and Note 5. 7.Derivative Financial Instruments in the Notes to Consolidated Financial Statements included in this ~~report for additional information.~~

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

The Dodd-Frank Wall Street Reform and Consumer Protection Act (the "Dodd-Frank Act") provides for federal oversight of the over-the-counter derivatives market and entities that participate in that market and mandates that the Commodity Futures Trading Commission (the "CFTC"), the SEC, and federal regulators of financial institutions adopt rules or regulations implementing the Dodd-Frank Act and providing definitions of terms used in the Dodd-Frank Act.

The CFTC has finalized other regulations implementing the Dodd-Frank Act's provisions regarding trade reporting, margin, clearing, and trade execution; however, some regulations remain to be finalized and it is not possible at this time to predict when the CFTC will adopt final rules. For example, the CFTC has re-proposed regulations setting position limits for certain futures and option contracts in the major energy markets and for swaps that are their economic equivalents. Certain bona fide hedging transactions are expected to be made exempt from these limits. Also, it is possible that under recently adopted margin rules, some registered swap dealers may require us to post initial and variation margins in connection with certain swaps not subject to central clearing.

The Dodd-Frank Act and any additional implementing regulations could significantly increase the cost of some commodity derivative contracts (including through requirements to post collateral, which could adversely affect our available liquidity), materially alter the terms of some commodity derivative contracts, limit our ability to trade some derivatives to hedge risks, reduce the availability of some derivatives to protect against risks we encounter, and reduce our ability to monetize or restructure our existing commodity derivative contracts. If we reduce our use of derivatives as a consequence, our results of operations may become more volatile and our cash flows may be less predictable, which could adversely affect our ability to plan for and fund capital expenditures. Increased volatility may make us less attractive to certain types of investors. Finally, the Dodd-Frank Act was intended, in part, to reduce the volatility of oil and natural gas prices, which some legislators attributed to speculative trading in derivatives and commodity instruments related to oil and natural gas. If the implementing regulations result in lower commodity prices, our revenues could be adversely affected. Any of these consequences could adversely affect our business, financial condition and results of operations.

report.

The oil and natural gas industry is highly competitive, and our ~~small~~ size ~~puts~~may put us at a disadvantage in competing for resources.

The oil and natural gas industry is highly ~~competitive.~~competitive particularly in the Midland Basin and the Delaware Basin 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~~somewhat 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~~presently a component of our business strategy. IfHowever, even 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 relatively 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.

Our future results will suffer if we do not effectively manage our expanded operations.

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As a result of our recent acquisitions, the size and geographic footprint of our business has increased. Our future success will depend, in part, upon our ability to manage this expanded business, which may pose substantial challenges for management, including challenges related to the management and monitoring of new operations and basins and associated increased costs and complexity. We may also face increased scrutiny from governmental authorities as a result of the increase in the size of our business. There can be no assurances that we will be successful or that we will realize the expected benefits currently anticipated from our recent acquisitions.

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~~

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.

Our business and operations have been and may continue to be adversely affected by the ongoing COVID-19 pandemic.

The spread of COVID-19 and variants caused 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 may continue to have an adverse effect on our business, financial condition and results of operations. The continued spread of COVID-19 and variants could also negatively impact the availability of key personnel necessary to conduct our business. If COVID-19 or its variants continue to

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spread or the response to contain or mitigate any such pandemics are unsuccessful, we could continue to experience material adverse effects on our business, financial condition and results of operations.

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 ~~federal Safe Drinking Water Act (“SDWA”)~~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. For example, a federal Bureau of Land Management (the “BLM”) rulemaking for hydraulic fracturing practices on federal and Indian lands resulted in a March 2015 final rule that requires public disclosure of chemicals used in hydraulic fracturing, confirmation that the wells used in fracturing operations meet proper construction standards and development of plans for managing related flowback water. In June 2016, a federal district court judge in Wyoming struck down the final rule, finding that the BLM lacked congressional authority to promulgate the rule. The BLM appealed that ruling. However, in July 2017, the BLM initiated a rulemaking to rescind the final rule and reinstate the regulations that existed immediately before the published effective date of the rule. In light of the BLM’s proposed rulemaking, in September 2017, the U.S. Court of Appeals for the Tenth Circuit dismissed the appeal and remanded with directions to vacate the lower court’s opinion, leaving the final rule in place. On December 29, 2017, the BLM published a final rule rescinding the March 2015 final rule. 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.

We may be subject to regulation that restricts our ability to discharge water produced as part of our oil, natural gas and natural gas liquid production operations. Productive zones frequently contain water that must be removed for the oil, natural gas and natural gas liquid to produce, and our ability to remove and dispose of sufficient quantities of water from the various zones will determine whether we can produce oil, natural gas and natural gas liquid in commercial quantities. The produced water must be transported from the leasehold and/or injected into disposal wells. The availability of disposal wells with sufficient capacity to receive all of the water produced from our wells may affect our ability to produce our wells. Also, the cost to transport and dispose of that water, including the cost of complying with regulations concerning water disposal, may reduce our profitability. We have entered into various water management services agreements in Texas and New Mexico which provide for the disposal of our produced water by established counterparties with large integrated pipeline networks. If these counterparties fail to perform, we may have to shut in wells, reduce drilling activities, or upgrade facilities for water handling or treatment. The costs to dispose of this produced water may increase for a number of reasons, including if new laws and regulations require water to be disposed in a different manner.

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. States such as Texas and New Mexico have adopted, or are considering adopting, laws and regulations that may restrict or prohibit oilfield fluid disposal in certain areas or underground disposal wells, and state agencies implementing those requirements may issue orders directing certain wells in areas where seismic incidents have occurred to restrict or suspend disposal well operations or impose standards related to disposal well construction and monitoring. For example, the RRC previously issued a notice to operators in ~~December 2016,~~ the ~~EPA released its final report regarding~~Midland area to reduce daily injection volumes following multiple earthquakes above a 3.5 magnitude over an 18-month period. The notice also required disposal well operators to provide injection data to RRC staff to further analyze seismicity in the ~~potential impacts~~area. In 2021, the NMOCD announced a new plan for responding to increased seismic activity in the Permian Basin. Under the new plan, pending permits for wastewater injection in certain areas will be subject to additional reporting and monitoring requirements. Producers can be subject to substantial penalties and fines for failing to comply with these requirements. While we cannot predict the ultimate outcome of ~~hydraulic fracturing on drinking water resources, concluding~~this notice, any action that ~~“water cycle” activities associated with hydraulic fracturing may impact drinking water resources under certain circumstances such as water withdrawals~~temporarily or permanently restricts the availability of disposal capacity 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~~or other 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 disposalmay increase our costs 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.~~

have other adverse impacts on our operations.

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, which could become more frequent or severe due to climate change, could adversely affect our ability to conduct drilling, completion and production activities in the areas where we operate.

Our ~~exploration,~~ exploitation and development activities and equipment could be adversely affected by extreme weather conditions, such as ~~hurricanes,~~severe storms 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. Intense drought and increased water scarcity can adversely impact hydraulic fracturing and refining operations. These constraints and the resulting shortages or high costs could delay or temporarily halt our operations or the operations of our midstream providers and

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materially increase our operation and capital costs, which could have a material adverse effect on our business, financial condition and results of operations.

~~Climate~~

Our operations are subject to a series of risks arising out of the threat of climate change ~~legislation or regulations restricting emissions of "greenhouse gases"~~that could result in increased operating costs, limit the areas in which we may conduct oil, natural gas and ~~reduced~~natural gas liquid exploration and production activities, and reduce demand for the oil, natural gas and natural gas ~~liquids~~liquid we produce.

Studies over recent years have indicated that emissions of certain gases may be contributing to warming of the Earth's atmosphere. In response, increasingly governments have been adopting domestic and international climate change regulations that require reporting and reductions of the emission of such greenhouse gases. Methane, a primary component of natural gas, and carbon dioxide, a byproduct of burning oil, natural gas and refined petroleum products, are considered greenhouse gases. Internationally, the United Nations Framework Convention on Climate Change, the Kyoto Protocol and the Paris Agreement address greenhouse gas emissions, and international negotiations over climate change and greenhouse gases are continuing. Meanwhile, several countries, including those comprising the European Union, have established greenhouse gas regulatory systems.

In the United States, many states, either individually or through multi-state regional initiatives, have begun implementing legal measures to reduce emissions of greenhouse gases, primarily through emission inventories, emission targets, greenhouse gas cap and trade programs or incentives for renewable energy generation, while others have considered adopting such greenhouse gas programs.

Atno comprehensive climate change legislation has been implemented at the federal ~~level, the Obama Administration pledged for the Paris Agreement to meet an economy-wide target in 2025 of reducing greenhouse gas emissions by 26-28% below the 2005~~ level. ~~To help achieve these reductions, federal agencies have been~~However, President Biden has highlighted addressing climate change ~~through~~as a ~~variety~~priority of ~~administrative actions. The~~his administration, which includes certain potential initiatives for climate change legislation to be proposed and passed into law. Moreover, federal regulators, state and local governments, and private parties have taken (or announced that they plan to take) actions that have or may have a significant influence on our operations. For example, in response to findings that emissions of carbon dioxide, methane and other GHGs endanger public health and the environment, the EPA ~~thus issued greenhouse gas~~has adopted regulations under existing provisions of the CAA that, among other things, establish Prevention of Significant Deterioration (“PSD”) construction and Title V operating permit reviews for certain large stationary sources that are already potential major sources of certain principal, or criteria, pollutant emissions. Facilities required to obtain PSD permits for their GHG emissions also will be required to meet “best available control technology” standards that will be established by the states or, in some cases, by the EPA for those emissions. These EPA rules could adversely affect our operations and restrict or delay our ability to obtain air permits for new or modified sources. In addition, the EPA has adopted rules requiring the monitoring and reporting ~~regulations that cover~~of GHG emissions from specified onshore and offshore oil and ~~natural~~gas production sources in the United States on an annual basis, which include certain of our operations.

The federal regulation of methane from oil and gas facilities ~~among other industries. Beyond measuring and reporting,~~has been subject to substantial uncertainty in recent years. In June 2016, the EPA ~~issued an “Endangerment Finding” under Section 202(a) of the Clean Air Act, concluding certain greenhouse gas pollution threatens the public health~~finalized NSPS, known as Subpart OOOOa, that establish emission standards for methane and welfare of current and future generations. The finding served as the first step to issuing regulations that require permits for and reductions in greenhouse gas emissions for certain facilities. In March 2014, moreover, then President Obama released a Strategy to Reduce Methane Emissions that included consideration of both voluntary programs and targeted regulations for the oil and natural gas sector. Consistent with that strategy, the EPA issued final rules in 2016 forVOCs from new and modified oil and natural gas production ~~sources (including hydraulically fractured oil wells, natural gas well sites,~~and natural gas processing ~~plants, natural gas gathering~~ and ~~boosting stations and natural gas~~ transmission ~~sources) to reduce emissions of methane as well as volatile organic compound and toxic pollutants. However, in May 2017~~facilities. In September 2020, the EPA temporarily stayed implementing portions of the new rule and in June 2017 proposed a two year stay of new requirements, and more recently the head of the EPA has announced the current administration's intent to roll back or repeal most, if not all, of the Obama administration's regulations restricting future greenhouse gas emissions. In June 2017, President Trump announced that the United States intends to withdraw from the Paris Agreement and to seek negotiations either to reenter the Paris Agreement on different terms or a separate agreement. In August 2017, the U.S. Department of State officially informed the United Nations of the intent of the United States to withdraw from the Paris Agreement. The Paris Agreement provides for a four-year exit process beginning when it took effect in November 2016, which would result in an effective exit date of November 2020. The United States' adherencefinalized amendments to the ~~exit process and/or~~2016 standards that removed the ~~terms on which the United States may re-enter the Paris Agreement or a separately negotiated agreement are unclear at this time.~~

~~In the courts, several decisions have been issued that may increase the risk of claims being filed by governments~~transmission and private parties against companies that have significant greenhouse gas emissions. Such cases may seek to challenge air emissions permits that greenhouse gas emitters apply for and seek to force emitters to reduce their emissions or seek damages for alleged climate change impacts to the environment, people, and property.

The direction of future U.S. climate change regulation is difficult to predict given the current uncertainties surrounding the policies of the Trump Administration. The EPA may or may not continue developing regulations to reduce greenhouse gas emissionsstorage segment from the oil and natural gas ~~industry. Even~~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. Subsequently, the U.S. Congress approved, and President Biden has signed into law, a resolution under the Congressional Review Act to repeal the September 2020 revisions to the methane standards, effectively reinstating the prior standards. In response to President Biden’s executive order, in November 2021, the EPA issued a proposed rule that, if ~~federal efforts in this area slow, states may continue pursuing climate regulations. Any laws~~finalized, would establish Quad Ob as new source and Quad Oc as first-time existing source standards of performance for methane and VOC emissions for the crude oil and natural gas source category. Owners or ~~regulations~~operators of affected emission units or processes would have to comply with specific standards of performance that may include leak detecting using optical gas imaging and subsequent repair requirements, reduction of regulated emissions through capture and control systems, zero-emission requirements for certain equipment or processes and operations and maintenance requirements. In November 2022, the EPA published a supplemental proposal which, among other items, would impose expanded inspection, monitoring and emissions control requirement on oil and gas sites, as well as strengthen requirements related to emissions from equipment and routine flaring. The proposal would also establish a “Super Emitter Response Program” that would require operator response to emissions events exceeding 200 pounds per hour, as detected by regulatory authorities or qualified third-parties. The proposal is currently subject to public comment and is expected to be ~~adopted~~finalized in 2023. Separately, certain provisions of the IRA 2022 address methane regulation by imposing the first federal fee on excess methane emissions. As a result, we cannot predict the scope of any final methane regulatory requirements or the cost to ~~restrict~~comply with such requirements. However, given the long-term trend toward increasing regulation, future federal GHG regulations of the oil and gas industry remain a significant possibility.

Internationally, the United Nations-sponsored “Paris Agreement” requires member states to individually determine and submit non-binding emissions reduction targets every five years after 2020. President Biden has recommitted the United States to the Paris Agreement and, in April 2021, announced a goal of reducing the United States’ emissions by 50-52% below 2005 levels by 2030. In November 2021, the international community gathered again at COP26, during which multiple announcements were made, including a call for parties to eliminate certain oil and natural gas subsidies and pursue further action on non-CO2 GHGs. These goals were reaffirmed at COP27 in November 2022. Relatedly, the United States and European Union jointly announced the launch of the “Global Methane Pledge,” which aims to cut global methane pollution at least 30% by 2030 relative to 2020 levels, including “all feasible reductions” in the energy sector. The impacts of these orders, pledges, agreements and any legislation or regulation promulgated to fulfill the United States’ commitments under the Paris Agreement, COP26 or other international conventions cannot be predicted at this time. Concern over the threat of climate change has also resulted in increasing political risks in the United States, including climate-change related pledges made by President Biden and other public office representatives. On January 27, 2021, President Biden signed an executive order calling for substantial action on climate change, including, among other things, the increased use of zero-emissions vehicles by the federal government, the elimination of subsidies provided to the oil and natural gas industry and increased emphasis on climate-related risks across

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agencies and economic sectors. Additionally, in November 2021, the Biden Administration released “The Long-Term Strategy of the United States: Pathways to Net-Zero Greenhouse Gas Emissions by 2050,” which establishes a roadmap to net zero emissions in the United States by 2050 through, among other things, improving energy efficiency; decarbonizing energy sources via electricity, hydrogen, and sustainable biofuels; and reducing non-CO2 GHG emissions, such as methane and nitrous oxide.

Increasingly, oil and natural gas companies are exposed to litigation risks associated with the threat of climate change. A number of parties have brought suits against oil and natural gas companies in state or federal court for alleged contributions to, or failures to disclose the impacts of, climate change. We are not currently party to any such litigation, but could be named in future actions making similar claims of liability. To the extent that societal pressures or political or other factors are involved, it is possible that such liability could be imposed without regard to our causation of or contribution to the asserted damage, or to other mitigating factors.

Additionally, in response to concerns related to climate change, companies in the oil and natural gas industry may be exposed to increasing financial risks. Financial institutions, including investment advisors and certain sovereign wealth, pension and endowment funds, may elect in the future to shift some or all of their investments into non-oil and natural gas 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 in future not to provide funding for oil and natural gas companies. Many of the largest U.S. banks have made net zero commitments and have announced that they will be assessing financed emissions across their portfolios and taking steps quantify and reduce those emissions. In addition, at COP26, the Glasgow Financial Alliance for Net Zero (“GFANZ”) announced that commitments from over 450 firms across 45 countries had resulted in over $130 trillion in capital committed to net zero goals. The various sub-alliances of GFANZ generally require participants to set short-term, sector-specific targets to transition their financing, investing and/or underwriting activities to net zero emissions by 2050. These and other developments in the financial sector could lead to some lenders restricting access to capital for or divesting from certain industries or companies, including the oil and natural gas sector, or requiring that borrowers take additional steps to reduce their GHG emissions. There is also a risk that financial institutions will be required to adopt policies that have the effect of ~~greenhouse gases~~reducing the funding provided to the oil and natural gas industry. For example, the Federal Reserve has joined the Network for Greening the Financial System (“NGFS”), a consortium of financial regulators focused on addressing climate-related risks in the financial sector and, in November 2021, the Federal Reserve issued a statement in support of the efforts of the NGFS to identify key issues and potential solutions for the climate-related challenges most relevant to central banks and supervisory authorities. A material reduction in the capital available to the oil and natural gas industry could make it more difficult to secure funding for exploration, development, production, transportation and processing activities, which could result in decreased demand for our products or otherwise adversely impact our financial performance.

The adoption and implementation of new or more stringent international, federal or state legislation, regulations or other regulatory initiatives related to climate change or GHG emissions from oil and natural gas facilities could result in increased costs of compliance or costs of consumption, thereby reducing demand for, oil and natural gas. Additionally, political, litigation, and financial risks may result in (i) restriction or cancellation of certain oil and natural gas production activities, (ii) incurrence of obligations for alleged damages resulting from climate change, or (iii) impairment of our ability to continue operating in an economic manner. One or more of these developments could have a material adverse effect on our business, financial condition and results of operations.

Moreover, climate change may also result in various physical risks such as the increased frequency or intensity of extreme weather events or changes in meteorological and hydrological patterns, that could adversely impact our financial condition and operations, as well as those of our suppliers or customers. Such physical risks may result in damage to our facilities, or otherwise adversely impact our operations, such as if we become subject to water use curtailments in response to drought, or demand for our products, such as to the extent warmer winters reduce the demand for energy for heating purposes. Such physical risks may also impact the infrastructure on which we rely to produce or transport our products. One or more of these developments could have a material adverse effect on our business, financial condition and operations. In addition, while our consideration of changing weather conditions and inclusion of safety factors in design is intended to reduce the uncertainties that climate change and other events may potentially introduce, our ability to mitigate the adverse impacts of these events depends in part on the effectiveness of our facilities and our disaster preparedness and response and business continuity planning, which may not have considered or be prepared for every eventuality.

Restrictions on drilling activities intended to protect certain species of wildlife may adversely affect our ability to conduct drilling activities in some of the areas where we operate.

Oil and natural gas operations in our operating areas can be adversely affected by seasonal or permanent restrictions on drilling activities designed to protect certain wildlife, such as those restrictions imposed under the federal ESA. Seasonal restrictions may limit our ability to operate in protected areas and can intensify competition for drilling rigs, oilfield equipment, services, supplies and qualified personnel, which may lead to periodic shortages when drilling is allowed. These constraints and the

40

resulting shortages or high costs could delay our operations and materially increase our operating and capital costs. Permanent restrictions imposed to protect endangered species could prohibit drilling in certain areas or require the implementation of expensive mitigation measures. These risks are underscored by the FWS’ listing as endangered under the ESA the lesser prairie-chicken in eastern New Mexico and the southwest Texas Panhandle and the Sacramento Mountains checkerspot butterfly in New Mexico. The designation of previously unprotected species in areas where we operate as threatened or endangered, such as the recent designation of lesser prairie chickens in southwestern Texas as endangered, could cause us to incur ~~additional operating~~increased costs ~~such as costs~~arising from species protection measures or could result in limitations on our exploration and production activities that could have an adverse impact on our ability to ~~purchase~~develop and ~~operate emissions controls, to obtain emission allowances or to pay emission taxes, and reduce demand for~~produce our ~~oil and natural gas.~~

reserves.

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 isare primarily sold in ~~a limited number of~~two geographic markets in Texas and one in New Mexico 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~~lifting of prior restrictions on the exporting of oil and natural gas.

We

From time to time, federal ~~income tax deductions currently available with respect to oil~~ and ~~natural gas exploration and development are eliminated as a result of future legislation.~~

~~In past years,~~state level legislation has been proposed that would, if enacted into law, make significant changes to ~~U.S.~~ tax laws, including to certain key ~~U.S.~~ federal and state income tax provisions currently available to oil and natural gas exploration ~~development~~ and ~~production~~development companies. Such legislative changes have included, but have not been limited to, (i) the ~~repeal~~elimination of the percentage depletion allowance for oil and natural gas properties, (ii) the elimination of current deductions for intangible drilling and development costs, (iii) ~~the elimination of the deduction for certain domestic production activities, and (iv)~~ an extension of the amortization period for certain geological and geophysical ~~expenditures. The Tax Cuts and Jobs Act~~expenditures, (iv) the elimination of ~~2017 (the “TCJA”) did not directly affect deductions currently available to the oil and natural gas industry but any future changes in U.S. federal income tax laws could eliminate or postpone~~ certain other tax deductions ~~that currently are~~and relief previously available ~~with respect~~ to oil and natural gas ~~development,~~companies and (v) an increase in the federal income tax rate applicable to corporations such as us. It is unclear whether these or ~~increase costs,~~similar changes will be enacted and, if enacted, how soon any such changes could ~~have an adverse effect~~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 ~~financial position, results of~~ operations and cash flows.

~~The recently passed comprehensive tax reform bill could adversely affect our business and financial condition.~~

~~On December 22, 2017,~~

In addition, on August 16, 2022, President ~~Trump~~Biden signed into law the ~~TCJA that significantly changes the federal income taxation of business entities. The TCJA,~~IRA, which includes, among other things, ~~reduces the~~a corporate ~~income~~alternative minimum tax ~~rate to 21%~~(the "CAMT"), ~~partially limits the deductibility of business interest expense~~provides for an investment tax credit for qualified biomass property and ~~net operating losses, imposes~~introduces a ~~one-time~~one percent excise tax on ~~unrepatriated earnings from~~corporate stock repurchases after December 31, 2022. Under the CAMT, a 15 percent minimum tax will be imposed on certain ~~foreign~~adjusted financial statement income of "applicable corporations," which is effective beginning January 1, 2023. The CAMT generally treats a corporation as an applicable corporation in any taxable year in which the "average annual adjusted financial statement income" of the corporation and certain of its subsidiaries ~~taxes offshore earnings at reduced rates regardless of whether they are repatriated~~ and ~~allows the immediate deduction of certain capital expenditures instead of deductions~~affiliates for ~~depreciation expense over time.~~a three-taxable-year period ending prior to such taxable year exceeds $1 billion. We are ~~still evaluating~~currently assessing the potential impact of these legislative changes and will continue to evaluate the overall impact of ~~the TCJA to us. Notwithstanding the reduction in the corporate income~~other current, future and proposed regulations and interpretive guidance from tax authorities on our effective tax rate ~~we cannot yet conclude that the overall impact of the TCJA~~and consolidated balance sheets. We are unable to ~~us is positive.~~

predict whether any such changes or other proposals will ultimately be enacted.

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.

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.

We are affected by the adoption of laws, regulations and policy directives that, for economic, environmental protection or other policy reasons, could curtail exploration and development drilling for oil and gas. For example, in January 2021, President Biden signed an Executive Order directing the DOI to temporarily pause new oil and gas leases on federal lands and waters pending completion of a comprehensive review of the federal government’s existing oil and gas leasing and permitting program. In June 2021, a federal district court enjoined the DOI from implementing the pause and leasing resumed, although litigation over the leasing pause remains ongoing. In February 2022, another judge ruled that the Biden Administration’s efforts to raise the cost of climate change in its environmental assessments, would increase energy costs and damage state revenues from energy production. This ruling has caused federal agencies to delay issuing new oil and gas leases and permits on federal lands and waters. As a result, it is difficult to predict if and when such areas may be made available for future exploration activities.

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 at acceptable costs 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.

On March 21, 2022, the SEC proposed new rules relating to the disclosure of a range of climate-related risks. We are currently assessing the proposed rule, but at this time we cannot predict the costs of implementation or any potential adverse impacts resulting from the rule. According to the SEC’s Fall 2022 regulatory agenda, the proposed climate disclosure rule is scheduled to be finalized in April 2023. To the extent this rule is finalized as proposed, we could incur increased costs relating to the assessment and disclosure of climate-related risks, including increased legal, accounting and financial compliance costs, as well as making some activities more difficult, time-consuming and costly, and placing strain on our personnel, systems and resources. We may also face increased litigation risks related to disclosures made pursuant to the rule if finalized as proposed. In addition, enhanced climate disclosure requirements could accelerate the trend of certain stakeholders and lenders restricting or seeking more stringent conditions with respect to their investments in certain carbon-intensive sectors. The SEC proposes certain phase-in compliance dates for disclosures under the proposed rules, including for GHG emissions metrics.

Presently, and 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. WeIn the future and particularly if we expand the use of third parties to share operating risks, 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~~liquid 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.

We may ~~use~~incur substantial additional 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.

~~Non-operated properties are controlled~~

As an oil and gas producer, we face various security threats, including (i) cybersecurity threats to gain unauthorized access to, or control of, our sensitive information or to render our data or systems corrupted or unusable; (ii) threats to the security of our facilities and infrastructure or to the security of third-party facilities and infrastructure, such as gathering, transportation, processing, fractionation, refining and export facilities; and (iii) threats from terrorist acts. The potential for such security threats has subjected our operations to increased risks that ~~may not allow us to proceed with our planned capital expenditures. Activities~~could have a material and adverse effect on our ~~operated properties could also be limited~~business.

We rely extensively on information technology systems, including internally developed software, data hosting platforms, real-time data acquisition systems, third-party software, cloud services and other internally or ~~subject~~externally hosted hardware and software platforms, to ~~penalties.~~

~~We currently are not the operator of some of~~(i) estimate our ~~existing properties and, therefore, may not be able to influence production operations or further development activities. Joint ownership is customary in the~~ oil and ~~natural~~ gas industry and is generally conducted under the terms of a joint operating agreement (“JOA”), where one of the working interest owners is designated as the “operator” of the property. For non-operated properties, subject to the specific terms and conditions of the applicable JOA, if we disagree with the decision of a majority of working interest owners, we may be required, among other things, to postpone proposed activity or decline to participate in drilling and completing of wells. If we decline to participate, we might be forced to relinquish our interest through “in-or-out” elections or may be subject to certain non-consent penalties, as provided in a JOA. In-or-out elections may require a joint owner to participate or forever relinquish its position, typically only in specific wells or drilling units, although such relinquished positions could be of a larger scope. Non-consent penalties typically allow participating working interest owners to recover from the proceeds of production, if any, an amount equal to 200% to 500% of the non-participating working interest owner’s share of the cost of such operations. Further, even for properties operated by us, there may be instances where decisions related to drilling, completion and operating cannot be made in our sole discretion. In such instances, we could be limited in our development operations and subject to penalties as specified above if we choose not to participate in operations proposed by a majority of working interest owners.

Because we cannot control activities on properties we do not operate, we cannot directly control the timing of exploration and development projects. 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 exploration, acquisition and development 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. For example, software programs are used to interpret seismic data, manage drilling rigs, production equipment and gathering and transportation systems, as well as conduct reservoir modeling and reserve estimation for compliance reporting.

~~We are dependent on digital technologies including information systems and related infrastructure, to~~reserves, (ii) process and record financial and operating data, (iii) process and analyze all stages of our business operations, including exploration, drilling, completions, production, gathering and processing, transportation, pipelines and other related activities and (iv) communicate with our employees ~~business partners,~~ and ~~stockholders, analyze seismic~~vendors, suppliers and ~~drilling information, estimate quantities of oil and natural gas reserves as well as~~ other ~~activities related to~~third parties. Further, our ~~business. Our business partners, including vendors, service providers, purchasers of our production and financial institutions are also dependent~~reliance on ~~digital technology. The technologies needed to conduct oil and natural gas exploration, development and production activities make certain information the target of theft or misappropriation.~~

~~As dependence on digital technologies~~technology has increased ~~cyber incidents, including deliberate attacks or unintentional events,~~due to the increased use of personal devices, remote communications and other work-from-home practices adopted in response to the COVID-19 pandemic. Although we have ~~also increased. A cyber-attack could include gaining unauthorized access~~implemented and invested in, and will continue to ~~digital~~implement and invest in, controls, procedures and protections (including internal and external personnel) that are designed to protect our systems, ~~for~~identify and remediate on a regular basis vulnerabilities in our systems and related infrastructure and monitor and mitigate the ~~purposes~~risk of ~~misappropriating assets or sensitive information, corrupting~~ data ~~causing operational disruption, or result~~loss and other cybersecurity threats, such measures cannot entirely eliminate cybersecurity threats and the controls, procedures and protections we have implemented and invested in ~~denial-of-service on websites.~~

may prove to be ineffective.

Our ~~technologies,~~ systems and networks, and those of our business ~~partners~~associates, may become the target of ~~cyber-attacks~~cybersecurity attacks, including, without limitation, denial-of-service attacks; malicious software; data privacy breaches by employees, insiders or ~~information~~others with authorized access; cyber or phishing-attacks; ransomware; attempts to gain unauthorized access to our data and systems; and other electronic security breaches. If any of these security breaches ~~that~~were to occur, we could suffer disruptions to our normal operations, including our drilling, completion, production and corporate functions, which could materially and adversely affect us in a variety of ways, including, but not limited to, the following:

Further, strategic targets, such as surveillance, may remain undetected for an extended period of time. 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.

~~We are subject to litigation relating to Bold and the Bold Transaction, and we~~energy-related assets, may be ~~subject to additional litigation, any~~at a greater risk of ~~which could adversely affect our business, financial condition and operating results.~~

~~On June 7, 2017, litigation captioned~~ ~~Olenik v. Lodzinksi et al.~~ ~~was filed~~terrorist attacks or cybersecurity attacks than other targets in the ~~Delaware Court of Chancery seeking class action status, claiming a breach of fiduciary duty by our Board and others and challenging the fairness~~United States. Moreover, external digital technologies control nearly all of the ~~Bold Transaction. The plaintiff has requested an award of damages~~crude oil and natural gas distribution and refining systems in ~~an unspecified amount. The Company~~the U.S. and ~~the other defendants believe the suit is without merit~~abroad, which are necessary to transport and ~~have mounted a vigorous defense. In addition, we may be subject to additional litigation relating to Bold~~market our production. A cybersecurity attack directed at, for example, crude oil, natural gas liquids and natural gas distribution systems could (i) damage critical distribution and storage assets or the ~~Bold Transaction in the future. We cannot predict the outcome~~environment; (ii) disrupt energy supplies and markets, by delaying or preventing delivery of ~~the ongoing litigation~~production to markets; and (iii) make it difficult or ~~any litigation~~impossible to accurately account for production and settle transactions.

Any such terrorist attack or cybersecurity attack that ~~may arise in the future, nor can~~affects us, our customers, suppliers, or others with whom we ~~predict the amount of time and expense that will be required to resolve the ongoing litigation~~ do business and/or any other litigation. While we will evaluate and defend against the ongoing litigation and any other litigation vigorously, the costs of the defense, including legal fees of directors under indemnification obligations, and other effects of such litigationenergy-related assets could have ana material adverse effect on our business, ~~financial condition and results~~including disruption of ~~operations.~~

~~On August 18, 2017, litigation captioned~~ ~~Trinity Royal Partners, LP v. Bold Energy III LLC, et al.~~ ~~was filed with the 142nd Judicial District of the District Court in Midland County, Texas, asserting breach of contract and indemnity claims for alleged damages from~~our operations, damage to our reputation, a loss of ~~property relating~~counterparty trust, reimbursement or other costs, increased compliance costs, significant litigation exposure and legal liability or regulatory fines, penalties or intervention. Although we have business continuity plans in place, our operations may be adversely affected by significant and widespread disruption to ~~two oil~~our systems and ~~natural gas wells~~the infrastructure that supports our business. While we continue to evolve and modify our business continuity plans as well as our cyber threat detection and mitigation systems, there can be no assurance that they will be effective in ~~which Bold was~~avoiding disruption and business impacts. Further, our insurance may not be adequate to compensate us for all resulting losses, and the ~~operator. Trinity Royalty Partners,~~

cost to obtain adequate coverage may increase for us in the future and some insurance coverage may become more difficult to obtain, if available at all.

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.

Like many oil and natural gas companies, we are from time to time involved in various legal and other proceedings, such as title, royalty or contractual disputes, regulatory compliance matters and personal injury, environmental damage or property damage matters, in the ordinary course of our business. Furthermore, our assets may be negatively affected by legal proceedings brought by nongovernmental organizations and other advocacy groups against third parties, including the DOI. Such legal proceedings may seek drilling moratoria, recission of drilling permits or otherwise seek to restrict or frustrate oil and gas development. Such legal and regulatory proceedings are inherently uncertain and their results cannot be predicted. Regardless of the outcome, such proceedings could have an adverse impact on us because of legal costs, diversion of management and other personnel and other factors. In addition, it is possible that a resolution of one or more such proceedings could result in liability, penalties or sanctions, as well as judgments, consent decrees or orders requiring a change in our business practices, which could materially and adversely affect our business, operating results and financial condition. Accruals for such liability, penalties or sanctions may be insufficient, and judgments and estimates to determine accruals or range of losses related to legal and other proceedings could change from one period to the next, and such changes could be material.

We are a controlled company within the meaning of the NYSE corporate governance standards. Under the NYSE rules, a company of which more than 50% of the voting power is held by another person or group of persons acting together is a controlledholding company and ~~may elect not~~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 ~~comply with certain NYSE~~reimburse us for our corporate ~~governance requirements,~~and other overhead expenses, and to the extent EEH has available cash, we intend to cause EEH to make distributions to the holders of EEH Units, including ~~the requirements that:~~

~~a majority of the board of directors consist of independent directors;~~

~~the nominating and governance committee be composed entirely of independent directors with a written charter addressing the committee’s purpose and responsibilities; and~~

~~the compensation committee be composed entirely of independent directors with a written charter addressing the committee’s purpose and responsibilities.~~

~~These requirements will not apply to~~ us, as ~~long~~well as our wholly owned subsidiaries, Lynden Corp and Lynden 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, 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 and the Indenture. To the extent that we ~~remain a controlled company. Accordingly, you may not have~~need funds, and EEH or its subsidiaries are restricted from making such distributions under applicable law or regulation or under the ~~same protections afforded~~terms of their financing arrangements, or are otherwise unable to ~~stockholders of companies that are subject to all of the corporate governance requirements of the NYSE.~~

provide such funds, it could materially adversely affect our liquidity and financial condition.

Holders of Class A Common Stock and our 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~~Earthstone's Third Amended and Restated Certificate of ~~Incorporation.~~Incorporation, as amended (the “Certificate of Incorporation”). As of December 31, 2022, EnCap, ~~through its ownership~~affiliates of ~~Bold Holdings, may be deemed to~~Post Oak and affiliates of Warburg beneficially own approximately ~~63%~~40.1%, 7.9% and 9.2%, respectively, of our voting ~~interests. In addition, certain affiliates controlled by EnCap directly own approximately 8% of our Class A Common Stock. As a significant stockholder, EnCap~~interests and, ~~certain of its~~along with their affiliates, could limit the ability of our other stockholders to approve transactions ~~that~~ they may deem to be in the best interests of our Company or delaying or preventing changes in control or changes in our management.

So

As long as EnCap and certain of its affiliates, affiliates of Post Oak, and affiliates of Warburg continue to control a significant amount of our outstanding voting securities, they will ~~continue~~have the authority to ~~be able to have~~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 ~~other~~ stockholders. In addition, EnCap and its affiliates, affiliates of Post Oak and affiliates of Warburg 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, affiliates of Post Oak and affiliates of Warburg 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 stockholders who own such a ~~controlling stockholder.~~

significant percentage of our voting securities.

As of March 1, 2023, there were approximately 34.3 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 Energy Holdings, LLC (“Bold Holdings”), an investment 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.

We may sell additional shares of Class A Common Stock or securities convertible into shares of our Class A Common Stock in subsequent offerings. WeAdditionally, we cannot predict the size of future issuances of our Class A Common Stock or other 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.

~~Bold Holdings 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, 2018, there were approximately 35.9 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 or its permitted transferees. Pursuant to 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. We also entered into a registration rights agreement pursuant to which the shares of Class A Common Stock which may be issued upon redemption or exchange of EEH Units and shares of Class B Common Stock, subject to certain limitations set forth therein, have been registered for subsequent offers and sales by Bold Holdings and its permitted transferees.

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. Our future dividend policy is within the discretion of our Board and will depend upon various factors, including our business, financial condition, results of operations, capital requirements, and investment opportunities. In addition, the ~~EEH~~ Credit Agreement ~~does not allow EEH~~and the Indenture limit EEH’s ability 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.~~

us.

Under ~~our Third Amended and Restated~~the Certificate of Incorporation, our Board is authorized to cause ~~the Company~~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~~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 ~~the Company~~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 ~~the Company,~~Earthstone, which means that the holders of preferred stock would be entitled to receive the net assets of ~~the Company~~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.~~

Our Class A Common Stock trades on the New York Stock Exchange. 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. ~~For instance, if~~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 ~~results are below the expectations of securities analysts and investors,~~performance could negatively impact the market price of our Class A Common ~~Stock could decrease, perhaps significantly. Other factors that may affect~~Stock. General market conditions, including the ~~market price~~level of, ~~our Class A Common Stock include:~~

~~changes in oil~~ and ~~natural gas prices;~~

~~actual or anticipated~~ fluctuations in, ~~our quarterly results~~the trading prices of ~~operations;~~

~~our liquidity;~~

~~sales of Class A Common Stock by our stockholders;~~

•

~~changes in our cash flow from operations or earnings estimates;~~

~~publication of research reports about us or the oil and natural gas exploration and production industry generally;~~

~~competition for, among other things, capital, acquisition of reserves, undeveloped land, and skilled personnel;~~

~~increases in market interest rates that may increase our cost of capital;~~

~~changes in applicable laws or regulations, court rulings, and enforcement and legal actions;~~

~~changes in market valuations of~~stocks generally could also have a similar ~~companies;~~

~~adverse market reaction to any indebtedness we may incur in the future;~~

~~additions or departures of key management personnel;~~

~~actions by our stockholders;~~

~~commencement of or involvement in litigation;~~

~~news reports relating to trends, concerns, technological or competitive developments, regulatory changes, and other related issues in our industry;~~

~~speculation in the press or investment community regarding our business;~~

~~political conditions in oil and natural gas producing regions of the world;~~

~~general market and economic conditions; and~~

~~domestic and international economic, legal, and regulatory factors unrelated to our performance.~~

~~In addition, U.S. securities~~negative impact. The stock markets ~~have experienced significant~~regularly experience price and volume ~~fluctuations. These fluctuations often have been unrelated~~volatility that affects many companies’ stock prices without regard to the operating performance of ~~companies in these markets. Market fluctuations and broad market, economic, and industry factors~~those companies. Volatility of this type may ~~negatively~~ affect the price of our Class A Common Stock, regardless of our operating performance. Any volatility or a significant decrease in the market price of our Class A Common Stock could also negatively affect our ability to make acquisitions using Class A Common Stock. Further, if we were to be the object of securities class action litigation as a result of volatility in our Class A Common Stock price or for other reasons, it could result in substantial costs and diversion of our management’s attention and resources, which could negatively affect our financial results.

We are subject to certain requirements of Section 404 of the Sarbanes-Oxley Act. If we fail to comply with the requirements of Section 404 or if we or our auditors identify and report material weaknesses in internal control over financial reporting, our investors may lose confidence in our reported information and our stock price may be negatively affected.

As of December 31, 2017, we are required to comply with certain provisions of Section 404 of the Sarbanes-Oxley Act of 2002 (the “Sarbanes-Oxley Act”). Section 404 requires that we document and test our internal control over financial reporting and issue our management’s assessment of our internal control over financial reporting. This section also requires that our independent registered public accounting firm issue an attestation report on such internal control. If we fail to comply with the requirements of Section 404 of the Sarbanes-Oxley Act, or if we or our auditors identify and report material weaknesses in our internal control over financial reporting, the accuracy and timeliness of the filing of our annual and quarterly reports may be materially adversely affected and could cause investors to lose confidence in our reported financial information, which could have a negative effect on the trading price of our Class A Common Stock. In addition, a material weakness in the effectiveness of our internal control over financial reporting could result in an increased chance of fraud and the loss of customers, reduce our ability to obtain financing and require additional expenditures to comply with these requirements, each of which could have a material adverse effect on our business, results of operations and financial condition.

The 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~~the Certificate of Incorporation could make it more difficult for a ~~third party~~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~~third-party more difficult.

Under ~~our Third Amended and Restated~~the Certificate of Incorporation and as expressly permitted by the Delaware General Corporation Law (the "DGCL"), 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.

None.

As of December 31, ~~2017,~~2022, we had approximately 13 gross vertical and 26 gross horizontal operated producing wells. Current internal estimates indicate approximately 526 potential gross, largely de-risked, operated drilling locations, the vast majority of which are in various benches of the Wolfcamp and the Spraberry formations. Of these 526 operated locations, 466 locations are expected to have an average working interest of 79%, whereas 60 locations are expected to be operated units where we would hold less than a 50% working interest. We are actively pursuing trades and acquisitions of additional acreage that would increase our working interest in these 60 locations. At this time, we expect that these 60 locations would have an average working interest of approximately 28%.

~~We also have a non-operated position of 6,167~~167,000 net acres in the Midland Basin that are highly contiguous on a project-by-project basis which allow us to drill multi-well pads. Of this acreage, 95% is operated and 5% is non-operated. Approximately 99% of ~~west Texas, located~~the Midland Basin net acreage is held by production. We hold an approximate 96% working interest in ~~Howard, Glasscock, Martin~~our operated acreage and ~~Midland counties, Texas.~~an approximate 45% working interest in our non-operated acreage. As of December 31, ~~2017,~~2022, we had ~~an interest~~interests in approximately ~~134~~263 gross / 206 net vertical and 26998 gross / 855 net horizontal ~~non-operated~~ producing wells, ~~with an average working interest~~ of ~~approximately 37%.~~

which we operate 177 vertical and 882 horizontal wells.

During 2022, we completed and began producing from 34 gross / 30.4 net operated wells and 20 gross / 4.1 net non-operated wells.

We have identified approximately 417 potential gross horizontal locations in various benches of the Wolfcamp and Spraberry formations with an estimated average working interest of approximately 28%. We have also identified approximately 117 potential gross vertical well locationsare currently operating two drilling rigs in the ~~Clearfork, Spraberry, Wolfcamp, Strawn and Fussleman formations with an estimated average working interest~~Midland Basin, both of ~~approximately 41%.~~

~~Eagle Ford Trend~~

which are currently drilling in Reagan County, Texas.

As of December 31, ~~2017,~~2022, we had approximately 45,000 net acres in the Delaware Basin in New Mexico that are highly contiguous on a project-by-project basis which allow us to drill multi-well pads. Of this acreage, 92% is operated and 8% is non-operated. Approximately 90% of the Delaware Basin net acreage is held ~~33,557~~by production. We hold an approximate 60% working interest in our operated acreage and an approximate 26% working interest in our non-operated acreage. As of December 31, 2022, we had interests in approximately 265 gross ~~(16,045 net)~~/ 94 net vertical and 265 gross / 144 net horizontal producing wells, of which we operate 101 vertical and 159 horizontal wells.

During 2022, we completed and began producing from 25 gross / 18.2 net operated wells and 4 gross / 0.7 net non-operated wells.

We are currently operating three drilling rigs in the Delaware Basin, all of which are currently drilling in Lea County, New Mexico.

As of December 31, 2022, we had approximately 3,000 net leasehold acres in ~~Fayette, Gonzales and Karnes counties, Texas. The acreage is located~~the Eagle Ford Trend, primarily in the crude oil window ~~of the Eagle Ford shale trend of south Texas~~in Gonzales and is prospective for the Eagle Ford, Austin Chalk and Upper Eagle Ford formations. We serve as the operator with a range of approximately 16% to 50% undivided ownership interest in substantially all of the acreage.

~~As of December 31, 2017, we~~Karnes counties which include 33 gross / 30 net operated ~~91 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 well. We have identified a total of approximately 165 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.

We have a non-operated position in 25,097 gross (2,863 net) acres within La Salle County, Texas. The acreage is prone to natural gas and condensate produced from the Eagle Ford formation. The two areas are summarized below:

a)

White Kitchen – We have an average working interest of approximately 15% in 7,075 gross acres, all of which is held by production. As of December 31, 2017, 30 gross wells were producing, and we have identified approximately 40 potential additional drilling locations.

wells.

b)

Martin Ranch – We have a 10% working interest in 18,022 gross acres. As of December 31, 2017, 31 gross wells were producing, and we have identified approximately 134 potential drilling locations in the acreage.

~~Additionally, we have a non-operated position in 2,055 gross (948 net) acres within Frio and Wilson counties of Texas.~~

~~Other~~

~~Our other 2017 operations primarily related to our recently divested Bakken properties, and other non-core oil and natural gas properties.~~

Oil and Natural Gas Reserves

As of December 31, ~~2017,~~2022, our estimated proved reserves totaled ~~79,976 MBOE~~367,936 MBoe and had a PV-10 value of approximately ~~$598.6 million~~$7.8 billion (reconciled in “Non-GAAP Measures” below) and a Standardized Measure of Discounted Future Net Cash Flows of approximately ~~$592.7 million,~~$6.7 billion, all of which relate to our properties in New Mexico and Texas. ~~In addition to the completion of the Bold Transaction in May 2017,~~During 2022, we incurred approximately ~~$81.1~~$530.6 million in capital expenditures, primarily drilling and completion ~~costs, during 2017.~~costs. We expect to further develop our properties through additional drilling.

~~2017~~

From January 1, ~~2017~~2022 to December 31, ~~2017,~~2022, our total estimated proved reserves increased ~~564%~~149% from ~~12,051 MBOE~~147,587 MBoe to ~~79,976 MBOE.~~367,936 MBoe. Of that, estimated proved developed reserves increased ~~113%~~183% from ~~9,361 MBOE~~93,575 MBoe to ~~19,961 MBOE~~264,721 MBoe and estimated proved undeveloped reserves increased ~~2,131%~~91% from ~~2,690 MBOE~~54,012 MBoe to ~~60,015 MBOE. These increases are primarily attributable to~~103,215 MBoe. The most significant increase in our total estimated proved reserves resulted from purchases of minerals in place resulting from the ~~Bold Transaction that closed~~Chisholm Acquisition, Bighorn Acquisition and Titus Acquisition, all completed in ~~May 2017.~~

2022.

The below table sets forth a summary of our estimated crude oil, natural gas and natural gas ~~liquids~~liquid reserves as of December 31, ~~2017,~~2022, 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, ~~2017. Proved~~2022. The prices used in estimating proved reserves are ~~estimated~~ 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, ~~2017~~2022 are summarized in the table below:

Oil

Natural Gas

NGL

Total

% of Total

Undiscounted Future Net Cash Flows

PV-10

Standardized Measure of Discounted Future Net Cash Flows

Future Capital Expenditures

(MBbl)

(MMcf)

(MBbl)

(MBOE) ⁽²⁾

Proved

($ In thousands)

($ In thousands)

($ In thousands)

($ In thousands)

PDP

10,854

21,387

3,754

18,172

23
%

$
414,383

$
253,156

$
250,644

$
—

PDNP

1,095

1,949

369

1,789

2
%

36,224

20,637

20,432

11,177

PUD

35,378

67,752

13,345

60,015

75
%

1,023,000

324,848

321,624

665,916

Total proved ⁽¹⁾

47,327

91,088

17,468

79,976

100
%

$
1,473,607

$
598,641

$
592,700

$
677,093

~~(1)~~

Includes 26.8 MMBbl of oil, 51.6 Bcf of natural gas and 9.9 MMBbl of NGL reserves attributable to noncontrolling interests. Additionally, $339.4 million of PV-10 and $320.1 million of standardized measure of discounted future net cash flows were attributable to noncontrolling interests.


	Oil (MBbl)	Natural Gas (MMcf)	Natural Gas Liquids (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	85,949	566,041	79,009	259,298	71	%	$	9,713,044	$	5,670,222	$	4,894,901	$	—
PDNP	2,810	8,721	1,159	5,423	1	%	268,801		170,452		147,145		7,000
PUD	49,641	167,404	25,673	103,215	28	%	3,953,685		1,948,945		1,682,455		1,200,597
Total proved (1)	138,400	742,166	105,841	367,936	100	%	$	13,935,530	$	7,789,619	$	6,724,501	$	1,207,597

~~(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).~~

(1)Includes 33.9 MMBbl of oil, 181.9 Bcf of natural gas and 25.9 MMBbl of natural gas liquids reserves attributable to noncontrolling interests. Additionally, $1.9 billion of PV-10 and $1.6 billion 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 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⁾

$
598,641

Future income taxes, discounted at 10%

(5,941
)
Standardized measure of discounted future net cash flows ⁽²⁾

$
592,700

	~~(1)~~	~~Includes $339.4 million attributable to noncontrolling interests.~~
Present value of estimated future net revenues (PV-10) (1)			$	7,789,619
Future income taxes, discounted at 10%			(1,065,118)
Standardized measure of discounted future net cash flows (2)			$	6,724,501

~~(2)~~

~~Includes $320.1 million~~(1)Includes $1.9 billion attributable ~~to noncontrolling interests.~~

~~Drilled But Uncompleted Wells~~

~~In order~~ to ~~achieve efficiencies from a pricing and logistics standpoint, our customary sequence of drilling and completion operations is~~noncontrolling interests.

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~~price as of December 31, ~~2017, 2016, and 2015 are~~2022 is based on the respective 12-month unweighted average of the first of the month prices of the ~~West Texas Intermediate~~WTI spot prices which equates to ~~$51.34~~$93.67 per ~~barrel, $42.75 per barrel, and $50.28 per barrel, respectively.~~barrel. The natural gas ~~prices~~price as of December 31, ~~2017, 2016 and 2015 are~~2022 is based on the respective 12-month unweighted average of the first of month prices of the Henry Hub spot price which equates to ~~$2.98~~$6.36 per ~~MMBtu, $2.48 per MMBtu and $2.59 per MMBtu, respectively.~~MMBtu. The natural gas ~~liquids prices~~liquid price used to value reserves as of December

31, ~~2017, 2016 and 2015~~2022 averaged ~~$22.59~~$39.24 per ~~barrel, $13.21 per barrel and $14.11 per barrel, respectively~~.barrel. All prices are adjusted by lease or field for energy content, transportation fees, and market ~~differentials.~~differentials, resulting in the aforementioned oil, natural gas and natural gas liquid reserves as of December 31, 2022 being valued using prices of $95.82 per barrel, $5.51 per MMBtu and $39.24 per barrel, respectively. All prices are held constant in accordance with SEC guidelines.

Proved undeveloped reserves (“PUDs”) increased from ~~2,690 MBOE~~54,012 MBoe to ~~60,015 MBOE~~103,215 MBoe or ~~2,131%~~91%, ~~for the year ended~~as of December 31, ~~2017~~2022 compared to ~~the year ended~~ December 31, ~~2016. Proved undeveloped reserves~~2021. PUDs represent ~~75%~~28% 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.~~ In accordance with our ~~2017~~December 31, 2022 year-end independent engineering reserve report, we plan to drill all of our individual PUD drilling locations within the ~~next~~ five ~~years.~~

years of original classification.

The consolidated net quantities of oil, natural gas and natural gas liquids produced and sold by us for the years ended December 31, ~~2017, 2016,~~2022, 2021 and ~~2015,~~2020, the average sales price per unit sold (excluding hedges) and the average production cost per unit are presented below:

Years Ended December 31,

2017

2016

2015

Sales Volumes:

Oil (MBbl)

1,828

878

904

Natural gas (MMcf)

3,260

2,171

2,143

Natural gas liquids (MBbl)

500

225

176

Barrels of oil equivalent (MBOE)*

2,872

1,465

1,437

Average prices realized:**

Oil (per Bbl)

$
48.43

$
39.13

$
44.09

Natural gas (per Mcf)

$
2.69

$
2.32

$
2.55

Natural gas liquids (per Bbl)

$
21.51

$
12.74

$
12.29

Barrels of oil equivalent (per BOE)

$
37.63

$
28.86

$
33.04

Production cost per BOE

$
6.84

$
10.28

$
10.73

*

~~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 2017, 2016 and 2015 have been marked-to-market in our Consolidated Statements of Operations as other income/expense; which means that all our realized gains/losses on these derivatives are reported in other income/expense.


	Years Ended December 31,
	2022		2021		2020
Sales Volumes:
Oil (MBbl)	11,866		4,381		3,180
Natural gas (MMcf)	54,392		14,505		7,282
Natural gas liquids (MBbl)	7,599		2,257		1,198
Barrels of oil equivalent (MBoe)*	28,531		9,055		5,591
Average daily production (Boe per day)	78,167		24,809		15,276
Average prices realized:**
Oil (per Bbl)	$	93.91	$	67.83	$	37.85
Natural gas (per Mcf)	$	5.59	$	3.50	$	1.18
Natural gas liquids (per Bbl)	$	36.45	$	31.76	$	13.03
Barrels of oil equivalent (per Boe)	$	59.41	$	46.34	$	25.85
Production cost per Boe***	$	8.08	$	5.45	$	5.21

* 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 2022, 2021 and 2020 have been marked-to-market in our Consolidated Statements of Operations and both the realized and unrealized amounts are reported as other income/expense.

*** Production costs include lifting costs, gathering, processing and compression costs and workover costs. The increase from 2021 to 2022 was primarily related to higher gathering and processing costs, and workover costs from our recent acquisitions. In addition, in 2022, we experienced inflationary costs in certain areas such as labor, and other services and products.

52

The following tables ~~below~~ 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, ~~2017, 2016,~~2022, 2021 and ~~2015.~~

2020.

Midland Basin

~~No results for 2015~~


	Years Ended December 31,
	2022		2021		2020
Sales Volumes:
Oil (MBbl)	6,533		3,817		2,687
Natural gas (MMcf)	45,429		14,263		7,079
Natural gas liquids (MBbl)	6,457		2,191		1,141
Barrels of oil equivalent (MBoe)*	20,562		8,385		5,007
Average daily production (Boe per day)	56,333		22,972		13,681
Average prices realized:**
Oil (per Bbl)	$	96.05	$	67.75	$	37.68
Natural gas (per Mcf)	$	5.56	$	3.50	$	1.15
Natural gas liquids (per Bbl)	$	36.71	$	31.81	$	13.08
Barrels of oil equivalent (per Boe)	$	54.32	$	45.10	$	24.83
Production cost per Boe	$	7.22	$	4.95	$	4.81

* Barrels of oil equivalent have been ~~presented below~~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 ~~they represent~~we did not elect to apply hedge accounting.

Delaware Basin


	Years Ended December 31,
	2022		2021		2020
Sales Volumes:
Oil (MBbl)	4,833		—		—
Natural gas (MMcf)	8,739		—		—
Natural gas liquids (MBbl)	1,089		—		—
Barrels of oil equivalent (MBoe)*	7,379		—		—
Average daily production (Boe per day)	20,216		—		—
Average prices realized:**
Oil (per Bbl)	$	90.76	$	—	$	—
Natural gas (per Mcf)	$	5.74	$	—	$	—
Natural gas liquids (per Bbl)	$	34.78	$	—	$	—
Barrels of oil equivalent (per Boe)	$	71.37	$	—	$	—
Production cost per Boe	$	9.88	$	—	$	—

* Barrels of oil equivalent have been calculated on the ~~operating results~~basis of ~~properties acquired in~~six thousand cubic feet (Mcf) of natural gas equal to one barrel of oil equivalent (Boe).

** Amounts exclude the ~~Bold Transaction completed in May 2017 and in the Lynden Arrangement completed in May 2016.~~

Years Ended December 31,

2017

2016

Sales Volumes:

Oil (MBbl)

1,059

139

Natural gas (MMcf)

1,821

367

Natural gas liquids (MBbl)

351

69

Barrels of oil equivalent (MBOE)*

1,714

269

Average prices realized:**

Oil (per Bbl)

$
48.42

$
45.13

Natural gas (per Mcf)

$
2.49

$
2.42

Natural gas liquids (per Bbl)

$
23.01

$
15.81

Barrels of oil equivalent (per BOE)

$
37.29

$
30.68

Production cost per BOE

$
4.65

$
10.06

impact of cash paid/received on settled derivative contracts as we did not elect to apply hedge accounting.

*

~~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).~~

53

**

~~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,

2017

2016

2015

Sales Volumes:

Oil (MBbl)

535

525

672

Natural gas (MMcf)

772

947

1,172

Natural gas liquids (MBbl)

94

118

143

Barrels of oil equivalent (MBOE)*

758

801

1,011

Average prices realized:**

Oil (per Bbl)

$
49.86

$
39.30

$
45.29

Natural gas (per Mcf)

$
3.09

$
2.39

$
2.61

Natural gas liquids (per Bbl)

$
18.52

$
12.91

$
13.26

Barrels of oil equivalent (per BOE)

$
40.65

$
30.50

$
35.01

Production cost per BOE

$
8.80

$
6.86

$
8.84

*

~~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).~~


	Years Ended December 31,
	2022		2021		2020
Sales Volumes:
Oil (MBbl)	500		565		493
Natural gas (MMcf)	225		243		204
Natural gas liquids (MBbl)	53		65		57
Barrels of oil equivalent (MBoe)*	590		670		584
Average daily production (Boe per day)	1,617		1,837		1,595
Average prices realized:**
Oil (per Bbl)	$	96.42	$	68.35	$	38.82
Natural gas (per Mcf)	$	6.03	$	3.89	$	1.95
Natural gas liquids (per Bbl)	$	38.44	$	29.94	$	11.96
Barrels of oil equivalent (per Boe)	$	87.43	$	61.88	$	34.62
Production cost per Boe	$	15.47	$	11.68	$	8.61

**

~~Amounts exclude the impact of cash paid/received on settled derivative contracts as we did not elect to apply hedge accounting.~~

* 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, ~~2017.~~2022. A net well represents our percentage of ownership of a gross well.

Oil

Natural Gas

Total

Gross Wells

Net Wells

Gross Wells

Net Wells

Gross Wells

Net Wells

Midland Basin

193

94

2

1

195

95

Eagle Ford Trend

109

46

56

6

165

52

Other ⁽¹⁾

1

1

-

-

1

1

~~(1)~~

~~Other primarily includes our non-core oil and natural gas properties, which were divested in February 2018.~~


	Oil		Natural Gas		Total
	Gross	Net	Gross	Net	Gross	Net
Midland Basin	1,253	1,055	8	6	1,261	1,061
Delaware Basin	369	164	161	73	530	237
Eagle Ford Trend	33	30	—	—	33	30
Total	1,655	1,249	169	79	1,824	1,328

Acreage

The following table summarizes our gross and net developed and undeveloped acreage by ~~state~~area as of December 31, ~~2017.~~2022. Net acreage represents our percentage ownership of gross acreage.

Developed

Undeveloped ⁽¹⁾

Total

State

Gross

Net

Gross

Net

Gross

Net

Texas

77,098

39,532

23,588

6,989

100,686

46,521

Other

960

770

6,979

3,141

7,939

3,911

Total

78,058

40,302

30,567

10,130

108,625

50,432


	Developed		Undeveloped		Total
	Gross	Net	Gross	Net	Gross	Net
Midland Basin	133,645	122,404	50,612	44,852	184,257	167,256
Delaware Basin	39,945	18,838	41,519	25,667	81,464	44,505
Eagle Ford Trend	4,269	2,787	—	—	4,269	2,787
Total	177,859	144,029	92,131	70,519	269,990	214,548

54

The following table summarizes, as of December 31, ~~2017,~~2022, the portion of our gross and net acreage subject to expiration over the next three years if not successfully developed or renewed.


	Expiring Acreage																	Expiring Acreage
	2018				2019				2020				Total					2023		2024		2025		Total
	Gross		Net		Gross		Net		Gross		Net		Gross		Net			Gross	Net	Gross	Net	Gross	Net	Gross	Net
Midland Basin		761		761		160		160		170		170		1,091		1,091	Midland Basin	—	—	442	442	791	791	1,233	1,233
Delaware Basin																	Delaware Basin	393	393	320	320	280	280	993	993
Eagle Ford Trend		4,342		2,171		14,446		2,254		3,709		1,473		22,497		5,898	Eagle Ford Trend	—	—	—	—	—	—	—	—
Other		6,979		3,141		—		—		—		—		6,979		3,141
Total		12,082		6,073		14,606		2,414		3,879		1,643		30,567		10,130	Total	393	393	762	762	1,071	1,071	2,226	2,226

~~We have development agreements related to certain~~

Approximately 99% of ~~our operated leases in~~ the Midland Basin ~~which require us~~net acreage is held by production, approximately 90% of the Delaware Basin net acreage is held by production and approximately 100% of the Eagle Ford net acreage is held by production. On a combined basis, our total net acreage is approximately 97% held by production.

Drilling Activities

The following table sets forth information with respect to ~~drill 42~~(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,
	2022		2021		2020
	Gross	Net	Gross	Net	Gross	Net
Development wells:
Productive	82	52	27	16	24	13
Dry(1)	1	1	—	—	—	—
Exploratory wells:
Productive	—	—	—	—	—	—
Dry	—	—	—	—	—	—
Total wells:
Productive	82	52	27	16	24	13
Dry	1	1	—	—	—	—
Total	83	53	27	16	24	13

(1)The dry hole category includes one gross (0.6 net) operated well that was unsuccessful due to mechanical issues.

The figures in the table above do not include twenty-three gross wells (31 net wells) over the next five years. If we do not drill the required wells, we would be in default of the agreements. All of the aforementioned wells are included in management’s development plan.

~~Exploratory Wells~~(15.3 net) that were drilled and ~~Development Wells~~

~~Set forth below for the three years ended December 31, 2017 is information concerning the number of wells we drilled during the years indicated.~~

Net Exploratory Wells
Drilled

Net Development Wells
Drilled

Total Net
Productive and
Dry Wells

Year

Productive

Dry

Productive

Dry

Drilled

2017

—

—

11.0

—

11.0

2016

—

—

7.7

—

7.7

2015

—

—

7.2

—

7.2

~~Present Activities~~

~~As of March 1, 2018, we had 7 gross (5.3 net) operated wells and 4 gross (0.8 net) non-operated wells~~uncompleted or in the process of ~~drilling or completing.~~

being completed at December 31, 2022, all of which are classified as PUDs as of that date and are expected to begin producing in the first quarter of 2023.

I~~tem~~

Item 3. Legal Proceedings

In the ordinary course of business, we may be involved in litigation and claims arising out of our operations. The Company’s threshold for disclosing material environmental legal proceedings involving a governmental authority where potential monetary sanctions are involved is $1 million. As of December 31, ~~2017,~~2022, 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.~~Note 15. Commitments and Contingencies in the Notes to Consolidated Financial Statements included in Item 8 of this report.

Item 4. Mine Safety Disclosures

Not applicable.

55

PART II

Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities

Market Information ~~for Common Stock~~

Shares of our Class A Common Stock are listed on the NYSE under the symbol “ESTE.” ~~The following table sets forth the reported high and low sales prices of our Class A Common Stock for the periods indicated:~~

Class A Common Stock Price

Period

High

Low

2017

First Quarter

$
15.50

$
11.26

Second Quarter

$
15.00

$
9.07

Third Quarter

$
11.68

$
8.49

Fourth Quarter

$
11.13

$
7.85

2016

First Quarter

$
14.19

$
10.75

Second Quarter

$
15.93

$
10.12

Third Quarter

$
11.66

$
7.67

Fourth Quarter

$
15.71

$
8.02

Holders

~~Holders~~

As of March 1, ~~2018,~~2023, there were approximately ~~2,000~~1,800 holders of record of our Class A Common Stock and ~~approximately 30~~six holders of record of our Class B Common Stock.

There is no public market for our Class B Common Stock.

Unregistered Sales of Equity Securities

None, except to the extent previously included by Earthstone in a Quarterly Report on Form 10-Q or Current Report on Form 8-K.

Dividends

We have never paid dividends on our Class A Common Stock ~~or Class B Common Stock~~ and do not ~~intend~~have any current plans to pay a ~~dividend in the foreseeable future.~~dividend. Furthermore, the ~~EEH~~ Credit Agreement ~~restricts~~and the Indenture restrict 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.

Holders of Class B Common Stock are not entitled to participate in any cash dividends declared by the Board.

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 2017

—

—

—

—

November 2017

—

—

—

—

December 2017

31,614

$
10.63

—

—

~~(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.


	Total Number of Shares Purchased		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 2022	3,000,000	(1)	$	14.58	—	—
November 2022	—		—		—	—
December 2022	46,350	(2)	$	14.23	—	—

(1)On October 11, 2022, Earthstone repurchased an aggregate of 3,000,000 shares of Class A Common Stock, held by affiliates of Warburg in a private transaction, for an aggregate purchase price of approximately $43.7 million, or $14.58 per share. The acquisition of the shares from affiliates of Warburg was not part of a publicly announced program to repurchase shares of our Class A Common Stock.

(2)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.

Performance Graph

The following performance graph and related information shall not be deemed “soliciting material” or to be “filed” with the SEC, nor shall information be incorporated by reference into any future filing under the Securities Act or the Exchange Act, except to the extent that we specifically incorporate it by reference into such filing.

In 2022, we chose to compare our cumulative total stockholder return against the SPDR S&P Oil & Gas Exploration & Production ETF (“XOP”), instead of the S&P 500 Oil & Gas Exploration & Production Select Industry Index (“E&P Index”). If a company selects a different index or peer group from that used in the immediately preceding fiscal year, the company’s stock performance must be compared with both the newly-selected index or peer group and the index used in the immediately preceding year. Accordingly, the following graph reflects a comparison of the cumulative total stockholder return of our Class A Common Stock beginning December 31, ~~2013~~2017 through December 31, ~~2017,~~2022, relative to the cumulative total returns of the S&P 500 Index, the E&P Index and the ~~S&P Oil & Gas Exploration & Production Select Industry Index.~~XOP. The graph assumes the investment of $100 on December 31, ~~2012~~2017 in our Class A Common Stock and each index and the reinvestment of all dividends, if any. ~~The identity of the companies included in the S&P Oil & Gas Exploration & Production Select Industry Index will be provided upon request.~~

12/31/2012

12/31/2013

12/31/2014

12/31/2015

12/31/2016

12/31/2017

Earthstone Energy, Inc.

$
100.00

$
119.43

$
151.71

$
85.93

$
88.70

$
68.62

S&P 500 Index

$
100.00

$
132.39

$
150.51

$
152.59

$
170.84

$
208.14

S&P 500 Oil & Gas Exploration & Production Index

$
100.00

$
127.09

$
88.85

$
56.23

$
77.09

$
69.33

56

I~~tem~~

Item 6. ~~Selected Financial Data~~

~~The following selected financial data should be read in conjunction with Item 7.~~ ~~Management’s Discussion and Analysis of Financial Condition and Results of Operations~~, and our Consolidated Financial Statements and the accompanying notes thereto included elsewhere in this report. In accordance with GAAP, the consolidated financial information and consolidated financial statements included herein for 2014 and prior period, are those of OVR and its subsidiaries. Prior to our acquisition of three operating subsidiaries of OVR in exchange for shares of our common stock in December 2014 (the “Exchange”). OVR, and its subsidiaries were pass through entities for income tax purposes and therefore no income tax expense was recorded for the historical periods prior to the year ended December 31, 2014. OVR was formed in December 2012 and was initially capitalized through the contribution of producing properties, acreage and working capital as well as cash commitments from investors. Upon initial capitalization, the contributed properties, acreage and working capital resulted in one owner retaining a controlling interest in OVR, and despite a change in management, GAAP required OVR to record the contributed properties at their historical cost basis even though such cost basis was in excess of the valuation agreed upon by members at the time of capitalization. GAAP required reporting higher DD&A provisions and significant impairments, in all years presented below, than would have been reported otherwise had the properties been recorded at the agreed upon valuation approximating fair value.

(In thousands, except per share and production amounts)

Years Ended December 31,

2017

2016

2015

2014

2013

Summary of Operating Data:

Sales volumes:

Oil (MBbl)

1,828

878

904

403

163

Natural gas (MMcf)

3,260

2,171

2,143

2,132

2,635

Natural gas liquids (MBbl)

500

225

176

124

134

Barrel of oil equivalent (MBOE)*

2,872

1,465

1,437

882

737

Average realized prices:

Oil (per Bbl)

$
48.43

$
39.13

$
44.09

$
86.29

$
98.32

Natural gas (per Mcf)

$
2.69

$
2.32

$
2.55

$
4.39

$
3.69

Natural gas liquids (per Bbl)

$
21.51

$
12.74

$
12.29

$
28.29

$
28.88

Summary of Operations:

Total revenues

$
108,078

$
42,269

$
47,464

$
47,611

$
29,634

Lease operating expenses

$
19,658

$
15,067

$
15,422

$
10,130

$
8,122

Severance taxes

$
6,060

$
2,198

$
2,582

$
2,002

$
1,225

Impairment expense

$
72,191

$
24,283

$
138,086

$
19,359

$
12,298

Depreciation, depletion and amortization

$
36,915

$
25,937

$
31,228

$
18,414

$
17,111

Pretax loss

$
(61,106
)

$
(54,013
)

$
(143,097
)

$
(6,729
)

$
(19,875
)
Income tax benefit (expense)

$
16,373

$
(528
)

$
26,442

$
(22,105
)

$
—

Net loss

$
(44,733
)

$
(54,541
)

$
(116,655
)

$
(28,834
)

$
(19,875
)
Net loss attributable to Earthstone Energy, Inc.

$
(12,514
)

$
(54,541
)

$
(116,655
)

$
(28,834
)

$
(19,875
)
Net loss per share attributable to Earthstone Energy, Inc.:**

Basic and diluted

$
(0.53
)

$
(2.92
)

$
(8.43
)

$
(3.11
)

$
(2.18
)

Summary of Cash Flows:

Net cash provided by (used in) operating activities

$
50,951

$
1,712

$
(10,440
)

$
75,788

$
15,283

Net cash used in investing activities

$
(86,303
)

$
(59,868
)

$
(66,602
)

$
(107,437
)

$
(117,116
)
Net cash provided by (used in) financing activities

$
48,107

$
45,092

$
(141
)

$
106,673

$
107,105

Summary Balance Sheet Data at Year End:

Net oil and natural gas properties

$
767,570

$
269,402

$
198,333

$
295,877

$
147,297

Total assets

$
834,417

$
316,512

$
264,944

$
451,388

$
189,858

Long-term debt

$
25,000

$
12,693

$
11,191

$
11,191

$
10,825

Total equity

$
725,732

$
241,457

$
199,873

$
316,528

$
148,922

Reserved

*

~~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).~~

**

~~For periods prior to the Exchange, earnings per share is calculated based on 9,124,452 shares which is the number of shares issued to OVR in December 2014 as a result of the Exchange.~~

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,” “guidance,” “target,” “potential,” “possible,” or “probable,” 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.

For a discussion and analysis of our financial condition and results of operations for the year ended December 31, 2021 compared to December 31, 2020, see “Part II, Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations” of our Annual Report on Form 10-K for the year ended December 31, 2021, which was filed with the SEC on March 9, 2022.

Overview

We are 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, ~~assets~~asset and corporate acquisitions and ~~mergers and, to a lesser extent, exploration activities.~~mergers. Our operations are all in the upstream segment of the oil and natural gas industry and all of our properties are onshore in the United States. ~~At present, our~~Our primary assets are located in the Midland Basin ~~of west~~in West Texas and the ~~Eagle Ford trend of south Texas.~~

Delaware Basin in New Mexico.

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

57

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~~EEH��s members other than Earthstone and Lynden US (collectively, the “Company” “our,” “we,” “us,” or similar terms).

Areas of Operation

Our primary focus is concentrated in the Midland Basin ~~of west~~in West Texas aand the Delaware Basin in New Mexico, both containing high oil and liquids rich ~~resource~~resources which provides us with multiple horizontal ~~target horizons, extensive~~targets with proven production ~~histories,~~results, long-lived reserves and historically high drilling success rates.

~~Midland Basin~~

Consolidation Focus

We ~~believe that the Midland Basin continues to have attractive economics and we expect to~~ continue to ~~focus~~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. We are focusing our attention on ~~growing our footprint through development drilling, acreage trades, asset acquisitions,~~acquisition and corporate merger ~~and acquisition opportunities. We are intensely focused on expansion~~opportunities that would increase the scale of our operations. In addition, we believe the current industry environment presents unique opportunities which could provide us the potential for further consolidation because of our financial strength. At the same time, we will seek to block up acreage in ~~the Midland Basin and production results continue~~close proximity to ~~be as good or better than we projected.~~

We have been operating a one drilling rig program in the Midland Basin and plan to maintain a one rig program throughout 2018, with a view toward adding a second rig at some point in 2018 predicated upon commodity prices, availability of quality services, our drilling results and liquidity. In February 2018, we completed drilling our 11th Midland Basin well. We currently have a rig drilling the first well of a two-well pad in Reagan County. At present we have five wells waiting on completion and expect to have an inventory of seven wells when we initiate completion operations in April 2018.

~~We continue to be active in~~existing acreage ~~trades and acquisitions in the Midland Basin which generally~~that would allow for longer horizontal laterals providing higher economic returns, increased operated inventory and greater operating efficiency.

~~Eagle Ford Trend~~

~~We recently completed an 11~~ In short, we believe we are well ~~drilling program in southern Gonzales County, Texas. Completion operations on the 11 wells began in November 2017 and were concluded in January 2018. We currently expect our 2018 drilling program~~qualified to continue to be ~~consistent with our 2017 program in this area. During each of~~a consolidator which could increase the second and third quarters of 2017, we entered into Joint Development Agreements ("JDA") for these wells. In each of the two JDA’s, the financial partner is obligated to pay a promoted (higher) share of the capital expenditures to earn 50%scale of our ~~interest in these units~~operations and ~~adjacent acreage. The two JDA’s reduced~~add value to our ~~overall capital expenditures~~

shareholders.

Midland Basin

by

As of December 31, 2022, we had approximately ~~$17 million in 2017, allowing us to shift capital resources from the Eagle Ford to the Midland Basin while still maintaining operating control over our Eagle Ford program.~~

~~Recent Developments~~

~~Bold Contribution Agreement~~

On May 9, 2017, Earthstone completed the Bold Contribution Agreement. The primary purpose of the Bold Contribution Agreement was to provide for the business combination between Earthstone and Bold, which owned significant developed and undeveloped oil and natural gas properties167,000 net acres in the Midland Basin ~~of west Texas (the “Bold Transaction”).~~

The Bold Transaction was structured in a manner commonly known as an “Up-C.” Under this structure and the Bold Contribution Agreement, (i) Earthstone recapitalized its common stock into two classes – Class A Common Stock and Class B Common Stock, and all of Earthstone’s existing outstanding Common Stock was recapitalizedthat are highly contiguous on a ~~one-for-one~~project-by-project basis ~~for Class A Common Stock (the “Recapitalization”); (ii) Earthstone transferred all of its membership interests in Earthstone Operating, LLC, Sabine River Energy, LLC, EF Non-Op, LLC~~which allow us to drill multi-well pads. Of this acreage, 95% is operated and Earthstone Legacy Properties, LLC (formerly Earthstone GP, LLC) and $36,071 in cash from the sale of Class B Common Stock to Bold Holdings (collectively, the “Earthstone Assets”) to EEH, in exchange for 16,791,296 EEH Units; (iii) Lynden US transferred all of its membership interests in Lynden Op to EEH in exchange for 5,865,328 EEH Units; (iv) Bold Holdings transferred all of its membership interests in Bold to EEH in exchange for 36,070,828 EEH Units and purchased 36,070,828 shares of Class B Common Stock issued by Earthstone for $36,071; and (v) Earthstone granted an aggregate of 150,000 fully vested shares of Class A Common Stock under the 2014 Plan to certain employees of Bold. Each EEH Unit, together with one share of Class B Common Stock, are convertible into one share of Class A Common Stock.

~~Upon closing~~5% is non-operated. Approximately 99% of the Bold Transaction on May 9, 2017, Bold Holdings owned approximately 61.4% of the outstanding shares of Class A Common Stock, on a fully diluted, as converted basis. The EEH Units and the shares of Class B Common Stock issued to Bold Holdings were not registered under the Securities Act, but were issued by EEH and Earthstone in reliance on the exemption provided under Section 4(a)(2) of the Securities Act.

Pursuant to the terms of the Bold Contribution Agreement, at the closing of the Bold Transaction, Earthstone, Bold Holdings, and the unitholders of Bold Holdings entered into the Registration Rights Agreement relating to the shares of Class A Common Stock issuable upon the exchange of the EEH Units and Class B Common StockMidland Basin net acreage is held by Bold Holdings or its unitholders. In accordance with the Registration Rights Agreement, Earthstone filed the Registration Statement with the SEC to permit the public resale of the shares of Class A Common Stock issued by Earthstone to Bold Holdings or its unitholdersproduction. We hold an approximate 96% working interest in ~~connection with the exchange of Class B Common Stock~~our operated acreage and ~~EEH Units~~an approximate 45% working interest in ~~accordance with the terms of the EEH LLC Agreement. On October 18, 2017, the Registration Statement was declared effective by the SEC.~~

On May 9, 2017, in connection with the closing of the Bold Contribution Agreement, Earthstone, EnCap, OVR, and Bold Holdings entered into the Voting Agreement, pursuant to which EnCap, OVR, and Bold Holdings agreed not to vote any shares of Class A Common Stock or Class B Common Stock held by them in favor of any action, or take any action that would in any way alter the composition of the Board from its composition immediately following the closing of the Bold Contribution Agreement as long as the Voting Agreement is in effect.

Immediately following the closing of the Bold Contribution Agreement, the Board was increased to nine members from eight members, four of which are designated by EnCap, three of which are independent, and two of which are members of management, including Earthstone’s Chief Executive Officer. At any time during the effectiveness of the Voting Agreement during which EnCap’s collective ownership of Earthstone exceeds 50% of the total issued and outstanding voting stock, EnCap may remove and replace one director that was not originally designated by EnCap, and his or her successors. Any such removal and replacement will be conducted in accordance with the provisions of Earthstone’s certificate of incorporation and bylaws then in effect. The Voting Agreement terminates on the earlier of (i) the fifth anniversary of the closing date of the Bold Contribution Agreement and (ii) the date upon which EnCap, OVR, and Bold Holdings collectively own, of record and beneficially, less than 20% of Earthstone’s outstanding voting stock.

On May 9, 2017, the closing sale price of the Class A Common Stock was $13.58 per share. On May 10, 2017, the Class A Common Stock was uplisted from the NYSE American to the NYSE where it is listed under the symbol “ESTE.”

~~Credit Agreement~~

On May 9, 2017, in connection with the closing of the Bold Transaction, the Company exited the ESTE Credit Agreement. At that time, all outstanding borrowings of $10.0 million under the ESTE Credit Agreement were repaid and $0.5 million of remaining unamortized deferred financing costs were expensed and included in Write-off of deferred financing costs in the Consolidated Statements of Operations.

~~On May 9, 2017, EEH entered into the EEH Credit Agreement.~~

The borrowing base under the EEH Credit Agreement is $185.0 million and is subject to redetermination on or about November 1st and May 1st of each year. The amounts borrowed under the EEH Credit Agreement bear annual interest rates at either (a) LIBOR plus 2.25% to 3.25% or (b) the prime lending rate of Bank of Texas plus 1.25% to 2.25%, depending on the amounts borrowed under the EEH Credit Agreement. Principal amounts outstanding under the EEH Credit Agreement are due and payable in full at maturity on May 9, 2022. All of the obligations under the EEH Credit Agreement, and the guarantees of those obligations, are secured by substantially all of EEH’s assets. Additional payments due under the EEH Credit Agreement include paying a commitment fee of 0.50% per year to the Lenders in respect of the unutilized commitments thereunder, as well as certain other customary fees.

The EEH Credit Agreement contains a number of covenants that, among other things, restrict, subject to certain exceptions, EEH’s ability to incur additional indebtedness, create liens on assets, make investments, enter into sale and leaseback transactions, pay dividends and make distributions or repurchase its limited liability interests, engage in mergers or consolidations, sell certain assets, sell or discount any notes receivable or accounts receivable and engage in certain transactions with affiliates.

In addition, the EEH Credit Agreement requires EEH to maintain the following financial covenants: a current ratio of not less than 1.0 to 1.0 and a leverage ratio of not greater than 4.0 to 1.0. Leverage ratio means the ratio of (i) the aggregate debt of EEH and its consolidated subsidiaries as at the last day of the fiscal quarter (excluding any debt from obligations relating to non-cash losses under FASB ASC 815 as a result of changes in the fair market value of derivatives) to (ii) the product of EBITDAX for such fiscal quarter multiplied by four. The term “EBITDAX” means, for any period, the sum of consolidated net income for such period plus (a) the following expenses or charges to the extent deducted from consolidated net income in such period: (i) interest, (ii) taxes, (iii) depreciation, (iv) depletion, (v) amortization, (vi) non-cash losses under FASB ASC 815 as a result of changes in the fair market value of derivatives, (vii) exploration expenses, (viii) impairment expenses, and (ix) non-cash compensation expenses and minus (b) to the extent included in consolidated net income in such period, non-cash gains under FASB ASC 815 as a result of changes in the fair market value of derivatives.

The EEH Credit Agreement contains customary affirmative covenants and defines events of default to include failure to pay principal or interest, breach of covenants, breach of representations and warranties, insolvency, judgment default, and if Frank A. Lodzinski ceases to serve and function as Chief Executive Officer of EEH and the majority of the Lenders do not approve of Mr. Lodzinski’s successor. Upon the occurrence and continuance of an event of default, the Lenders have the right to accelerate repayment of the loans and exercise their remedies with respect to the collateral.our non-operated acreage. As of December 31, ~~2017, EEH was~~2022, we had interests in ~~compliance with these covenants under~~approximately 263 gross / 206 net vertical and 998 gross / 855 net horizontal producing wells, of which we operate 177 vertical and 882 horizontal wells.

During 2022, we completed and began producing from 34 gross / 30.4 net operated wells and 20 gross / 4.1 net non-operated wells.

We are currently operating two drilling rigs in the ~~EEH Credit Agreement.~~

~~Uplisting~~Midland Basin, both of ~~Class A Common Stock~~

~~On May 8, 2017,~~which are currently drilling in Reagan County, Texas.

Delaware Basin

As of December 31, 2022, we had approximately 45,000 net acres in the ~~Board approved (i) the transfer~~Delaware Basin in New Mexico that are highly contiguous on a project-by-project basis which allow us to drill multi-well pads. Of this acreage, 92% is operated and 8% is non-operated. Approximately 90% of the ~~listing~~Delaware Basin net acreage is held by production. We hold an approximate 60% working interest in our operated acreage and an approximate 26% working interest in our non-operated acreage. As of December 31, 2022, we had interests in approximately 265 gross / 94 net vertical and 265 gross / 144 net horizontal producing wells, of which we operate 101 vertical and 159 horizontal wells.

During 2022, we completed and began producing from 25 gross / 18.2 net operated wells and 4 gross / 0.7 net non-operated wells.

We are currently operating three drilling rigs in the ~~Common Stock from the NYSE American to the NYSE, and (ii) the voluntary delisting of the Common Stock from the NYSE American. In connection with the closing of the Bold Transaction,~~Delaware Basin, all of the outstanding Common Stock was converted into Class A Common Stock, on a one-for-one basis. The Class A Common Stock began trading on the NYSE on May 10, 2017. The ticker symbol for the Class A Common Stock is “ESTE.”

~~Closing of Denver Office~~

~~On July 31, 2017, we closed our Denver office and provided severance to our employees working there.~~

~~Class A Common Stock Offering~~

In October 2017, Earthstone completed a public offering of 4,500,000 shares of Class A Common Stock, at a public offering price of $9.25 per share, receiving net proceeds of $39.4 million, after deducting underwriters’ fees and offering expenses of $2.4 million. The net proceeds were used to repay outstanding indebtedness under the EEH Credit Agreement.

~~Bakken Sale~~

~~In December 2017, we closed the Bakken Sale for a net cash consideration of approximately $26.4 million. The sale resulted~~which are currently drilling in a net gain of approximately $3.0 million recorded in Gain on sale of oil and gas properties in the Consolidated Statements of Operations. The effective date of the sale was December 1, 2017. The net proceeds were used to repay $25.0 million of outstanding borrowings under the EEH Credit Agreement and the remaining $1.4 million was retained in cash for current operating funds.

~~Divestiture of Non-Core Assets~~

During 2017, we sold certain non-core properties for a total cash consideration of approximately $7.5 million, while eliminating approximately $4.0 million of future abandonment obligations. The sales resulted in a net gain of approximately $6.1 million recorded in Gain on sale of oil and gas properties in the Consolidated Statements of Operations.

Lea County, New Mexico.

58

Results of Operations

Year ended December 31, ~~2017,~~2022 compared to the year ended December 31, ~~2016~~

Years Ended December 31,

2017

2016

Change

Sales volumes:

Oil (MBbl)

1,828

878

108
%
Natural gas (MMcf)

3,260

2,171

50
%
Natural gas liquids (MBbl)

500

225

123
%
Barrels of oil equivalent (MBOE) ⁽¹⁾

2,872

1,465

96
%

Average prices realized: ⁽²⁾

Oil (per Bbl)

$
48.43

$
39.13

24
%
Natural gas (per Mcf)

$
2.69

$
2.32

16
%
Natural gas liquids (per Bbl)

$
21.51

$
12.74

69
%

(In thousands)

Oil revenues

$
88,536

$
34,358

158
%
Natural gas revenues

8,777

5,046

74
%
Natural gas liquids revenues

10,765

2,865

276
%
Total revenues

$
108,078

$
42,269

156
%

Lease operating expense

$
19,658

$
15,067

30
%
Severance taxes

$
6,060

$
2,198

176
%
Rig idle and contract termination expense

$
—

$
5,059

100
%
Impairment expense

$
72,191

$
24,283

197
%
Depreciation, depletion and amortization

$
36,915

$
25,937

42
%
General and administrative expense

$
20,466

$
9,414

117
%
Stock-based compensation

$
6,601

$
3,301

100
%
Transaction costs

$
4,732

$
2,483

91
%
Gain on sale of oil and gas properties

$
9,105

$
8

NM

Interest expense, net

$
(2,699
)

$
(1,282
)

111
%
Write-off of deferred financing costs

$
(526
)

$
—

NM

Loss on derivative contracts, net

$
(7,986
)

$
(6,638
)

20
%
Income tax benefit (expense)

$
16,373

$
(528
)

NM

~~(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).~~

2021

~~(2)~~

~~Prices presented exclude any effects of oil and natural gas derivatives.~~


	Years Ended December 31,
	2022		2021		Change
Sales volumes:
Oil (MBbl)	11,866		4,381		171	%
Natural gas (MMcf)	54,392		14,505		275	%
Natural gas liquids (MBbl)	7,599		2,257		237	%
Barrels of oil equivalent (MBoe) (1)	28,531		9,055		215	%
Average daily production (BOE per day)	78,167		24,809		215	%

Average prices realized:
Oil (per Bbl)	$	93.91	$	67.83	38	%
Natural gas (per Mcf)	$	5.59	$	3.50	60	%
Natural gas liquids (per Bbl)	$	36.45	$	31.76	15	%

Average prices adjusted for realized derivatives settlements:
Oil ($/Bbl)	$	81.67	$	52.32	56	%
Natural gas ($/Mcf)	$	4.66	$	2.89	61	%
Natural gas liquids ($/Bbl)	$	36.45	$	31.76	15	%

(In thousands)
Oil revenues	$	1,114,343	$	297,177	275	%
Natural gas revenues	303,846		50,809		498	%
Natural gas liquids revenues	276,965		71,657		287	%
Total revenues	$	1,695,154	$	419,643	304	%

Lease operating expense	$	230,515	$	49,321	367	%
Production and ad valorem taxes	$	123,054	$	26,409	366	%

Depreciation, depletion and amortization	$	301,813	$	106,367	184	%

General and administrative expense (excluding stock-based compensation)	$	38,806	$	20,908	86	%
Stock-based compensation	$	35,369	$	21,014	68	%
General and administrative expense	$	74,175	$	41,922	77	%

Transaction costs	$	8,248	$	4,875	69	%
Gain on sale of oil and gas properties, net	$	13,900	$	738	1,783	%
Interest expense, net	$	(66,821)	$	(10,796)	519	%


Unrealized gain (loss) on derivative contracts	$	70,769	$	(40,795)	(273)	%
Realized loss on derivative contracts	$	(195,876)	$	(75,966)	158	%
Loss on derivative contracts, net	$	(125,107)	$	(116,761)	7	%


Income tax expense	$	(124,416)	$	(1,859)	6,593	%

~~NM – Not meaningful~~

(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).

59

Results of Operations Highlights

The Titus Acquisition, Bighorn Acquisition and Chisholm Acquisition (collectively, the “Acquisitions”) had a significant impact on our results of operations for the year ended December 31, 2022 compared to 2021. In addition, commodity prices have improved compared to 2021, further impacting our results of operations. Below is a discussion highlighting the impact of our recent acquisitions.

Oil revenues

For the year ended December 31, ~~2017,~~2022, oil revenues increased by ~~approximately~~ ~~$54.2~~$817.2 million or ~~158% relative~~275% compared to ~~the comparable period in 2016.~~2021. Of the increase, ~~approximately~~ ~~$8.2~~$702.9 million was attributable to an increase in volume and $114.3 million was attributable to an increase in our realized ~~price and $46.0 million was attributable to increased volume.~~ price. Our average realized price per Bbl increased from ~~$39.13~~$67.83 for the year ended December 31, ~~2016~~2021 to ~~$48.43~~$93.91 or ~~24%~~38% for the year ended December 31, ~~2017.~~ 2022. We had a net increase in the volume of oil sold of ~~950~~7,485 MBbls or ~~108%~~171%, ~~primarily due~~which included an increase of 7,136 MBbls related to the ~~Midland Basin properties we~~wells acquired in the ~~Bold Transaction.~~

Acquisitions and an increase of 349 MBbls from our development program during 2022, partially offset by other wells resulting from natural production declines in other wells.

Natural gas revenues

For the year ended December 31, ~~2017,~~2022, natural gas revenues increased by ~~$3.7~~$253.0 million or ~~74% relative~~498% compared to ~~the comparable period in 2016.~~2021. Of the increase, ~~approximately~~ ~~$0.8~~$222.8 million was due to increased sales volumes and $30.2 million was attributable to an increase in ~~our~~ realized ~~price and $2.9 million was attributable to increased volume.~~price. Our average realized price per Mcf increased 60% from ~~$2.32~~$3.50 for the year ended December 31, ~~2016~~2021 to ~~$2.69 or 16%~~$5.59 for the year ended December 31, ~~2017.~~2022. The total volume of natural gas produced and sold increased ~~1,089~~39,886 MMcf or ~~50% primarily due~~275% which included an increase of 39,666 MMcf related to the ~~Midland Basin properties we~~wells acquired in the ~~Bold Transaction.~~

Acquisitions, partially offset by a decrease of 220 MMcf in our other wells primarily resulting from natural production declines.

Natural gas ~~liquids~~liquid revenues

For the year ended December 31, ~~2017,~~2022, natural gas ~~liquids~~liquid revenues increased by ~~$7.9~~$205.3 million or ~~276% relative~~287% compared to ~~the comparable period in 2016.~~2021. Of the increase, ~~approximately~~ ~~$2.0~~$194.7 million was attributable to higher sales volumes and $10.6 million was due to an increase in our realized ~~price and $5.9 million was attributable to increased volume.~~ price. The volume of natural gas liquids produced and sold increased by ~~276~~5,343 MBbls or ~~123%~~237%, primarily ~~due~~resulting from an increase of 5,308 MBbls related to the ~~Midland Basin properties we~~wells acquired in the ~~Bold Transaction.~~

Acquisitions, partially offset by a decrease of 35 MBbls in our other wells primarily resulting from natural production declines.

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~~gathering, processing and transportation ~~fees,~~costs, insurance ~~ad valorem taxes~~expenses and overhead charges provided for in operating agreements.

LOE increased by ~~$4.6~~$181.2 million or ~~30%~~367% for the year ended December 31, ~~2017 relative~~2022 compared to ~~the comparable period in 2016,~~2021, primarily due to ~~costs to operate~~a $158.2 million increase resulting from the ~~producing assets~~LOE of the properties acquired in the ~~Bold Transaction~~Acquisitions and ~~added~~a $20.8 million increase resulting from new wells brought online as a result of our 2022 drilling program and ~~completion operations that were not present~~increased costs due to inflation in ~~the prior year period.~~

~~Severance~~2022.

Production and ad valorem taxes

~~Severance~~

Production and ad valorem taxes for the year ended December 31, ~~2017~~2022 increased by ~~$3.9~~$96.6 million or ~~176% relative~~366% compared to ~~the comparable period in 2016, primarily~~2021, due to an $84.7 million increase resulting from the properties acquired in the Acquisitions and an $11.9 million increase ~~in oil and natural gas prices. However, as a percentage of revenues from oil, natural gas, and natural gas liquids, severance taxes remained flat when compared to the prior year period.~~

~~Rig idle and contract termination expense~~

We incurred rig idle and termination expenses of $5.1 million during the year ended December 31, 2016. In July 2016, we entered into an agreement with a rig contractor to terminate our contract with the contractor. Per the terms of the agreement, a termination fee for the remaining commitment on the contract was due and the termination fees were retroactively applied to January 2016, when we suspended drilling and temporarily idled the drilling rig. In connection with the termination, we issued a three-year amortizing promissory note with a principal amount of $5.1 million, which was equivalent to the idle charges and contract termination fee.

~~Impairment~~

~~As a result of significant forward commodity price declines, as described below in~~ ~~Liquidity and Capital Resources, Commodity Prices, and the recording of certain acreage expirations, we recognized $72.2 million of non-cash asset impairments during~~ ~~the year ended December 31, 2017~~ ~~that have negatively impacted our results of operations and equity. These impairments consisted of $63.1 million~~related to our ~~proved oil and natural gas properties and $9.1 million to our unproved oil and natural gas properties, primarily to our properties located in~~ ~~the Eagle Ford Trend of south Texas. See~~ ~~Note 6. Oil and Natural Gas Properties~~ ~~in the Notes to Consolidated Financial Statements for a discussion of how impairments are measured.~~

other wells resulting from higher commodity prices.

Depreciation, depletion and amortization (“DD&A”)

DD&A increased for the year ended December 31, ~~2017~~2022 by ~~$11.0~~$195.4 million, or ~~42% relative~~184% compared to ~~the comparable period in 2016,~~ 2021, primarily due to ~~the addition of~~a $181.8 million increase in DD&A related to the assets acquired in the ~~Bold Transaction~~Acquisitions and ~~the Lynden Arrangement~~a $13.6 million increase in DD&A driven by higher production volumes and increased depletable costs related to the ~~depletable base, as well as~~development of our properties which were also affected by increased ~~production volumes.~~

costs due to inflation in 2022.

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 $11.1 million~~ for the year ended December 31, ~~2017 relative~~2022 increased by $32.3 million, or 77% compared to ~~the comparable period in 2016,~~2021, primarily due to ~~both~~an increase of $14.4 million in stock-based compensation expense. The remainder of the ~~retention of certain employees of Bold, as well as the payment and accrual of transition and severance totaling approximately $1.1 million to certain Bold and Denver office employees. Additionally,~~ ~~legal expenses increased~~increase was due to ~~litigation described~~an increase of $13.4 million in ~~Note 15. Commitments~~payroll and ~~Contingencies~~ ~~in the Notes to Consolidated Financial Statements.~~

~~Stock-based compensation~~

~~Stock-based compensation includes the expense~~employee costs associated with ~~grants under the 2014 Plan of restricted stock units (“RSUs”)~~increased headcount and $4.9 million primarily related to ~~employees~~an increase in professional fees due to overall increased operating activity and ~~non-employee directors. Stock-based compensation was $6.6 million for~~increased costs due to inflation in 2022.

60

Transaction costs

For the year ended December 31, ~~2017, as~~2022, transaction costs increased by $3.4 million compared to ~~$3.3 million in the prior year. However, the 2017 period is not comparable to the prior year period as the initial grant was made on May 20, 2016.~~ ~~The $3.3 million increase in stock-based compensation~~ ~~was~~2021, primarily due to ~~a $1.9 million increase during the current period due to the smaller amortization period beginning May 20, 2016 in the prior year~~legal and ~~$1.4 million due to the 2017 grants.~~

~~Transaction costs~~

~~Transaction costs consist primarily of financial advisory,~~ professional ~~and consulting~~ fees associated with the ~~Bold Transaction.~~

Chisholm Acquisition and certain divestiture transactions. See Note 4. Acquisitions and Divestitures in the Notes to Consolidated Financial Statements.

Gain on sale of oil and gas properties

During the year ended December 31, 2022, we sold certain non-core oil and gas properties located in Texas and New Mexico resulting in gains totaling $13.9 million. See Note 4. 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 increased from $10.8 million for the year ended December 31, ~~2017 was $2.7~~2021, to $66.8 million ~~compared to $1.3 million~~ for ~~the comparable period in 2016. The $1.4 million increase in interest expense was primarily due to increased borrowings during the current period.~~

~~Gain on sale of oil and gas properties~~

~~During~~ the year ended December 31, ~~2017, we sold~~ ~~all~~2022 due to higher average borrowings outstanding compared to the prior year primarily resulting from borrowings related to the Acquisitions and higher effective interest rates resulting from the issuance of ~~our oil and natural gas leases, oil and natural gas wells and associated assets located~~ the 8.000% Senior Notes in April 2022, as well as higher interest rates under the Credit Agreement during 2022. See Note12. Long-Term Debt in the ~~Williston Basin in North Dakota. We also sold~~ ~~certain of our non-core oil and natural gas properties in Texas, Montana, Oklahoma and North Dakota. In connection with these sales, we recorded gains totaling $9.1 million.~~ ~~See Note 3. Acquisitions and Divestitures~~ ~~in the~~ Notes to Consolidated Financial Statements.

Loss on derivative contracts, net

For the year ended December 31, ~~2017,~~2022, we recorded a net loss on derivative contracts of ~~$8.0~~$125.1 million, consisting of net realized losses on settlements of ~~$0.7~~our commodity hedges of $195.9 million, ~~and~~partially offset by unrealized mark-to-market ~~losses~~gains of ~~$7.3 million.~~$70.8 million related to our commodity hedges. For the year ended December 31, ~~2016,~~2021, we recorded a net loss on derivative contracts of ~~$6.6~~$116.8 million, consisting of net realized ~~gains~~losses on settlements of ~~$3.2~~our commodity hedges of $76.9 million ~~and~~partially offset by net realized gains on our interest rate swap of $0.9 million, along with unrealized mark-to-market losses of ~~$9.8 million.~~

$41.2 million related to our commodity hedges, partially offset by unrealized mark-to-market gains of $0.4 million related to our interest rate swap.

Income tax ~~benefit (expense)~~

Following the closing of the Bold Transaction, we continue to record an income tax provision consistent with our status as a corporation. Our corporate structure requires the filing of two separate consolidated U.S. Federal income tax returns and one Canadian income tax return resulting from 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. Following the Bold Transaction, 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.

expense

During the year ended December 31, ~~2017, we~~2022, the Company recorded a total income tax ~~benefit~~expense of ~~$16.4~~$124.4 million which ~~is primarily driven~~included (1) deferred income tax expense for Lynden US of $7.1 million as a result of its share of the distributable income from EEH, (2) deferred income tax expense for Earthstone of $107.8 million, which included a deferred income tax expense of $114.9 million, resulting from its share of the distributable income from EEH, offset by ~~the change in~~a $7.1 million release of valuation allowance, ~~associated with the Bold Transaction. For Lynden US, we recorded an~~(3) current income tax ~~benefit~~expense of ~~$8.6~~$1.8 million solely related to the Texas Margin Tax and (4) state deferred income tax expense of ~~which $4.8~~$0.8 million related to the ~~reduction of that amount in Lynden US’s deferred tax liability resulting from the federal~~Texas Margin Tax and $6.9 million related to New Mexico corporate income tax ~~rate reduction to 21% as described below. Additionally, we recorded an~~expense. Lynden Corp incurred no material income tax benefit for Earthstone of $7.7 million which resulted from a change in assessment of the realization of its net deferred tax assets due to the deferred tax liability that was recorded with respect to its investment in EEH as part of the Bold Transaction as an adjustment to Additional paid-in capital within the Consolidated Balance Sheets. Additionally, Earthstone recordedor loss, or related income tax expense of $12.6 million related to the reduction of that amount in its deferred tax asset resulting from the federal corporate income tax rate reduction to 21% as described below, which was fully offset by the reduction in its valuation allowance for that amount because the future realization of such loss cannot be reasonably assured and is subject to a full valuation allowance.

~~On December 22, 2017, the United States enacted tax reform legislation commonly known as the TCJA, resulting in significant modifications to existing law. Our consolidated financial statements~~or benefit, for the year ended December 31, 2017, reflect certain effects of the TCJA, which includes a reduction in our corporate tax to 21%. Consistent with Staff Accounting Bulletin No. 118 issued by the SEC, which provides for a measurement period of one year from the enactment date to finalize the accounting for effects of the TCJA, the Company provisionally recorded income tax expense of $7.8 million related to the TCJA. In accordance with SEC guidance, provisional amounts may be refined as a result of additional guidance from, and interpretations by, U.S. regulatory and standard-setting bodies, and changes in assumptions. In the subsequent period, provisional amounts will be adjusted for the effects, if any, of interpretative guidance issued after December 31, 2017, by the U.S. Department of the Treasury. The effects of the TCJA may be subject to changes for items that were previously reported as provisional amounts, as well as any element of the TCJA for which a provisional estimate could not be made, and such changes could be material.

The Company has made provisional computations of the impact of the TCJA as provided for under SAB 118, including transition tax on the mandatory deemed repatriation of foreign earnings and executive compensation limitations under Internal Revenue Code Section 162(m), among others. The Internal Revenue Service is expected to issue additional guidance clarifying provisions of the Act. As additional guidance is issued one or more of the provisional amounts may change.

2022.

~~Year ended December 31, 2016 compared to~~During the year ended December 31, ~~2015~~

Years Ended December 31,

2016

2015

Change

Sales volumes:

Oil (MBbl)

878

904

-3
%
Natural gas (MMcf)

2,171

2,143

1
%
Natural gas liquids (MBbl)

225

176

28
%
Barrels of oil equivalent (MBOE) ⁽¹⁾

1,465

1,437

2
%

Average prices realized: ⁽²⁾

Oil (per Bbl)

$
39.13

$
44.09

-11
%
Natural gas (per Mcf)

$
2.32

$
2.55

-9
%
Natural gas liquids (per Bbl)

$
12.74

$
12.29

4
%

(In thousands)

Oil revenues

$
34,358

$
39,849

-14
%
Natural gas revenues

5,046

5,457

-8
%
Natural gas liquids revenues

2,865

2,158

33
%
Total revenues

$
42,269

$
47,464

-11
%

Lease operating expense

$
15,067

$
15,422

-2
%
Severance taxes

$
2,198

$
2,582

-15
%
Rid idle and contract termination expense

$
5,059

$
—

NM

Impairment expense

$
24,283

$
138,086

-82
%
Depreciation, depletion and amortization

$
25,937

$
31,228

-17
%
General and administrative expense

$
9,414

$
9,711

-3
%
Stock-based compensation

$
3,301

$
—

NM

Transaction costs

$
2,483

$
589

322
%
Gain on sale of oil and gas properties

$
8

$
1,617

-100
%
Interest expense, net

$
(1,282
)

$
(722
)

78
%
(Loss) gain on derivative contracts, net

$
(6,638
)

$
6,431

-203
%
Income tax (expense) benefit

$
(528
)

$
26,442

-102
%

~~(1)~~

~~Barrels~~2021, we recorded total income tax expense of $1.9 million which included (1) deferred income tax expense for Lynden US of $0.9 million as a result of its share 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).~~

~~(2)~~

~~Prices presented exclude any effects of oil and natural gas derivatives.~~

~~NM – Not meaningful~~

~~Oil revenues~~

~~For~~ the ~~year ended December 31, 2016, oil revenues decreased~~distributable income from EEH, (2) deferred income tax expense for Earthstone of $6.3 million as a result of its share of the distributable loss from EEH, which was offset by ~~approximately~~ ~~$5.5~~a valuation allowance as future realization of the net deferred tax asset cannot be assured and (3) current income tax expense of $0.63 million, ~~or 14% relative~~all of which is related to state income tax expense and (4) deferred income tax expense of $0.33 million related to the ~~comparable period in 2015. Of the decrease,~~ ~~approximately~~ ~~$4.5 million was attributable to a decrease in our realized price and $1.0 million was attributable to decreased volume.~~ ~~Our~~ ~~average realized price per Bbl decreased from $44.09~~Texas Margin Tax. Lynden Corp incurred no material income or loss, or related income tax expense or benefit, for the year ended December 31, ~~2015~~2021.

Liquidity and Capital Resources

Sources of Cash

With two drilling rigs operating in the Midland Basin and three rigs operating in the Delaware Basin, we expect total 2023 capital expenditures of $725 to ~~$39.13 or 11% for~~$775 million which we expect to be funded by cash flows from operations. During the year ended December 31, ~~2016.~~ We2022, we generated $1.0 billion of cash flows from operating activities. As of December 31, 2022, we had available borrowings under our Credit Agreement of approximately $679.9 million. Additionally, on April 12, 2022, we issued $550.0 million of 8.000% senior notes due 2027 for net ~~decrease~~proceeds of approximately $537.2 million and, on April 14, 2022, we issued 280,000 shares of Series A Convertible Preferred Stock for net proceeds of approximately $279.3 million.

61

Although we expect cash flows from operations and capacity under our Credit Agreement to be sufficient to fund our expected 2023 capital program, we may also elect to raise funds through new debt or equity offerings or from other sources of financing. All of our sources of liquidity can be affected by the general conditions of the broader economy, force majeure events, challenging environmental regulations and fluctuations in ~~the volume~~commodity prices, operating costs and volumes produced, all of ~~oil sold of 26 MBbls. The Midland Basin properties we acquired in the Lynden Arrangement provided an additional 139 MBbls~~which affect us and our southern Gonzales and northern Karnes county assets that we acquired and began development on provided an additional 56 MBbls. These increases however, were offset by declines on our operated Eagle Ford properties of 197 MBbls, our non-operated Eagle Ford properties of 6 MBbls and Bakken/Three Forks properties of 10 MBbls. The remaining volume decrease was due to normal production declines and variability in sales volumes on our other properties mainly in Texas and North Dakota.

~~Natural gas revenues~~

~~For the year ended December 31, 2016,~~industry. We have no control over market prices for oil, natural gas ~~revenues decreased by $0.4 million~~ or ~~8% relative to the comparable period in 2015. Substantially all~~ ~~of the $0.4 million decrease was attributable to the decrease in our realized price.~~ ~~Our average realized price per Mcf decreased from $2.55 for the year ended December 31, 2015 to $2.32 or 9% for the year ended December 31, 2016.~~ ~~The total volume of natural gas produced and sold remained relatively consistent and increased by only 28 MMcf in total.~~

~~Natural gas liquids revenues~~

~~For the year ended December 31, 2016,~~ natural gas liquids, ~~revenues increased by $0.7 million or 33% relative~~although we may be able to influence the ~~comparable period in 2015.~~ Substantially all of the $0.7 million increase was attributable to the increase in volumes produced and sold. The volume of natural gas liquids produced and sold increased by 49 MBbls or 28%. The Midland Basin properties we acquired in the Lynden Arrangement and our southern Gonzales and northern Karnes county assets that we acquired and began development on provided an additional 72 MBbls. These increases were primary offset by declines on our non-operated Eagle Ford property.

~~Lease operating expense~~

~~LOE decreased by $0.4 million or 2% for the year ended December 31, 2016 relative to the comparable period in 2015.~~ ~~The decrease was due to our continued focus on reducing operating costs, economies of scale on our operated Eagle Ford property, and a decrease in the cost of oil field services in general.~~

~~Severance taxes~~

Severance taxes for the year ended December, 2016 decreased by $0.4 million or 15% relative to the comparable period in 2015, primarily due to the decline in oil and natural gas prices. As a percentage of revenues from oil, natural gas, and natural gas liquids, severance taxes remained relative flat and increased by only 1% due to the mix of production and revenues.

~~Rig idle and contract termination expense~~

We incurred rig idle and termination expenses of $5.1 million during the year ended December 31, 2016. In July 2016, we entered into an agreement with a rig contractor to terminate our contract with the contractor. Per the terms of the agreement, a termination fee for the remaining commitment on the contract was due and the termination fees were retroactively applied to January 2016, when we suspended drilling and temporarily idled the drilling rig. In connection with the termination, we issued a three-year amortizing promissory note with a principal amount of ~~$5.1 million, which was equivalent to~~realized revenues through the ~~idle charges and contract termination fee.~~

~~Impairment~~

~~As a result~~use of ~~large~~derivative contracts as part of our commodity price declines and in spite of our operating achievements, we recognized $24.3 million of noncash asset impairments in 2016 that negatively impacted our results of operations and equity. The impairments recorded in 2016 ~~consisted of $3.9 million to unproved properties, $2.9 million to proved properties and $17.5 million to goodwill.~~

~~Depreciation, depletion and amortization~~ ~~(“DD&A”)~~

~~DD&A decreased for the year ended December 31, 2016 by $5.3 million, or 17% relative to the comparable period in 2015,~~ ~~due to lower production volumes and reduced net book value in the 2016 period as a result of the significant impairments recognized at the end of 2015.~~ ~~The reserve decreases that lead to the impairments were primarily attributable to lower average oil and natural gas prices in 2016.~~

~~General and administrative expense (“G&A”)~~

~~G&A decreased by $0.3 million for the year ended December 31, 2016 relative to the comparable period in 2015. The decrease was primarily due to salary and benefits reductions taken during 2016.~~

~~Stock-based compensation~~

For the year ended December 31, 2016 we recognized expense of $3.3 million related to the RSU grants. The comparable prior period had no stock-based compensation expense since there were not any previously granted RSUs or other equity-based compensation granted.

~~Transaction costs~~

~~Transaction costs consist primarily of professional and consulting fees associated with the Bold Transaction and the Lynden Arrangement.~~

~~Interest expense, net~~

Interest expense for the year ended December 31, 2016 was $1.3 million compared to $0.7 million for the comparable period in 2015. The $0.6 million increase in interest expense was due to higher amortization of deferred financing costs and increased fees due to a larger credit facility.

risk management.

~~(Loss) gain on derivative contract, net~~

For the ended December 31, 2016, we recorded a net loss on derivative contracts of $6.6 million, consisting of net realized gains on settlements of $3.2 million and unrealized mark-to-market losses of $9.8 million. For the ended December 31, 2015, we recorded a net gain on derivative contracts of $6.4 million, consisting of net realized gains on settlements of $6.3 million and unrealized mark-to-market gains of $0.1 million. The primary reason for the current period loss as compared to the prior year gain is due to in improved commodity price environment in the latter part of 2016.

~~Income tax (expense) benefit~~

For the year ended December 31, 2016, we recorded $0.5 million of income tax expense related to Lynden Corp. Our corporate structure requires the filing of two separate consolidated U.S. Federal income tax returns. Taxable income of Earthstone, excluding the Lynden Corp. subsidiaries cannot be offset by tax attributes, including net operating losses of the Lynden Corp. subsidiaries, nor can taxable income of the Lynden Corp. subsidiaries be offset by tax attributes of Earthstone, excluding the Lynden Corp. subsidiaries. Excluding the Lynden Corp. subsidiaries, we have recorded significant income tax benefits in 2016 and 2015 resulting from property impairments which has resulted in a deferred tax asset. Because the future realization of this deferred tax asset could not be assured, we recorded a valuation allowance against our deferred tax asset of $12.2 million and $23.8 million in years ended December 31, 2016 and 2015, respectively.

~~Liquidity and Capital Resources~~

With the Bold Transaction, we acquired significant undeveloped acreage and future drilling locations. Drilling horizontal wells, generally consisting of 7,500 to 10,000-foot lateral lengths, in the Midland Basin is capital intensive. At December 31, 2017, we had approximately $23.0 million in cash and $160.0 million in unused borrowing capacity under the EEH Credit Agreement for a total of $183.0 million in liquidity. We currently estimate 2018 capital expenditures to be approximately $170.0 million, which assumes an approximate 20 well program running one rig for our operated acreage in the Midland Basin and an approximate 10 well program for our operated Eagle Ford acreage as well as some activity for our non-operated Midland Basin properties and land and infrastructure activities. We likely will outspend our cash flows provided by operating activities over at least the next twelve months from the date of this report based on current assumptions; however, we believe we will have sufficient liquidity with cash flows from operations and borrowings under ~~the EEH~~our Credit Agreement to meet our capital requirements for the next 12 months.

Working Capital

Working Capital (presented below) was a deficit of $130.0 million as of December 31, 2022 compared to a deficit of $89.2 million as of December 31, 2021, representing an increase in the deficit of $40.8 million. Of the $40.8 million increase in the working capital deficit, $61.2 million resulted from the change in the net fair value of our derivative contracts expected to settle in the 12 months subsequent to ~~meet~~December 31, 2022 resulting from changes in oil price futures as of December 31, 2022. The remaining decrease of $102.0 million primarily resulted from increased developmental activities in the current year. The components of working capital are presented below:


	December 31,
(in thousands)	2022		2021
Current assets:
Cash	$	—	$	4,013
Accounts receivable:
Oil, natural gas, and natural gas liquids revenues	161,531		50,575
Joint interest billings and other, net of allowance of $19 and $19 at December 31, 2022 and 2021, respectively	34,549		2,930
Derivative asset	31,331		1,348
Prepaid expenses and other current assets	18,854		2,549
Total current assets	246,265		61,415

Current liabilities:
Accounts payable	$	91,815	$	31,397
Revenues and royalties payable	163,368		36,189
Accrued expenses	80,942		31,704
Asset retirement obligation	948		395
Derivative liability	14,053		45,310
Advances	7,312		4,088
Operating lease liability	842		681
Finance lease liability	802		—
Other current liabilities	16,202		851

Total current liabilities	376,284		150,615

Working Capital Deficit	$	(130,019)	$	(89,200)

We expect that changes in receivables and payables related to our ~~cash requirements. We~~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 ~~evaluate and prepare operationally for~~be the ~~possible deployment of a second rig in~~largest variables affecting our ~~operated Midland Basin acreage.~~

working capital.

We expect to finance future ~~acquisition and~~ development activities ~~through available working capital,~~with cash flows from operating activities, borrowings under the ~~EEH~~ Credit Agreement and various means of corporate and project ~~financing, assuming we can access debt and equity markets. In addition,~~financing. Additionally, we may continue to partially finance our drilling activities through the sale of participating rights to ~~industry partners or~~ 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.

62

Cash Flows from Operating Activities

Cash flows provided by operating activities for the year ended December 31, ~~2017 were $51.0 million~~2022 increased to $1.0 billion compared to ~~$1.7~~$230.9 million for the year ended December 31, ~~2016. The increase in operating cash flows from the prior period was~~2021, primarily due to ~~changes in our working capital resulting from commodity price volatility~~the impact of the Acquisitions and the ~~producing assets acquired in~~timing of payments and receipts partially offset by the ~~Bold Transaction and the Lynden Arrangement. We believe we have sufficient liquidity and capital resources to execute our business plan over the next 12 months and for the foreseeable future.~~

~~We had working capital, defined~~cash settlement payments of derivative contracts as ~~Total current assets less Total current liabilities, as set forth in our Consolidated Balance Sheets, as a deficit of $21.8 million as of December 31, 2017~~ compared to ~~a deficit of $11.5 million as of December 31, 2016. The working capital deficit, as defined above, is a result of~~ the two-step drilling and completion process. Typically, we will drill numerous wells per pad and, once all the wells are drilled, they are completed and begin production. This process inherently involves timing differences between ultimate cash outflows and cash inflows.

prior year.

Cash Flows from Investing Activities

Cash flows used in investing activities for the year ended December 31, ~~2017 and 2016 were $86.3~~2022 increased to $2.0 billion from $426.2 million ~~and $59.9 million, respectively. Cash flows used in investing activities~~ for the year ended December 31, ~~2017~~ ~~included $55.6~~2021, due to approximately $1.5 billion in acquisitions of oil and gas properties, $491.8 million ~~required to complete the Bold Transaction and $65.3 million in capital expenditures primarily~~ related to the ~~drilling~~execution of our developmental program and ~~completion of wells in the Midland Basin on acreage acquired in the Bold Transaction,~~$2.1 million related to other property additions, partially offset by ~~$34.7~~$49.5 million in proceeds from ~~the divestiture~~sales of ~~certain non-core assets~~. ~~Cash flows used in investing activities for the year ended December 31, 2016~~ ~~related primarily to the cash required to complete the Lynden Arrangement.~~

oil and gas properties.

Cash Flows from Financing Activities

Cash flows provided by financing activities for the year ended December 31, ~~2017 were $48.1~~2022 increased to $945.3 million which consisted primarily of borrowings under the EEH Credit Agreement which were used to repay all outstanding borrowings under Bold’s credit agreement assumed by EEH in the Bold Transaction and proceeds from ~~the Class A Common Stock offering completed in October 2017~~. ~~Cash flows provided by financing activities~~$197.9 million for the year ended December 31, ~~2016 were $45.1~~2021. On April 12, 2022, we issued $550.0 million ~~which consisted primarily~~ of 8.000% senior notes due 2027 for net proceeds ~~from the common stock offering completed~~of approximately $537.2 million and, on April 14, 2022, we issued 280,000 shares of Series A Convertible Preferred Stock for net proceeds of approximately $279.3 million, partially offset by $43.9 million paid to repurchase 3.0 million shares of our Class A Common Stock in ~~June 2016.~~

late 2022.

Capital Expenditures

We have set our 2018 capital budget, which currently assumes a one-rig program for our operated acreage in the Midland Basin and a 10 well program for our operated Eagle Ford acreage. We will continue to evaluate and prepare operationally for the possible deployment of a second rig in our operated Midland Basin acreage in the latter half of 2018. Our anticipated capital expenditures for 2018 are currently estimated at $170 million.

Our accrual basis capital expenditures for the years ended December 31, ~~2017, 2016~~2022, 2021 and ~~2015~~2020 were as follows:


								Years Ended December 31,
	Years Ended December 31,							(In thousands)
	2017		2016		2015			2022		2021		2020
Drilling and completions	$	76,253	$	25,982	$	46,388	Drilling and completions	$	529,478	$	127,884	$	66,580
Leasehold costs		3,067		2,595		10,474	Leasehold costs	1,118		2,608		208
Land		1,816		—		—

Total capital expenditures	$	81,136	$	28,577	$	56,862	Total capital expenditures	$	530,596	$	130,492	$	66,788

The ~~net proceeds from the offering were used to repay~~following table sets forth our outstanding ~~indebtedness under the EEH Credit Agreement.~~

~~Credit Agreement~~

~~In May 2017, in connection with the closing of the Bold Transaction, we became party to the EEH Credit Agreement. As of~~derivative contracts at December 31, ~~2017, we had a $185.0 million borrowing base under~~2022. When aggregating multiple contracts, the ~~EEH Credit Agreement, of which $25.0 million was~~weighted average contract price is disclosed.

The following table sets forth our outstanding ~~bearing an annual interest rate of 3.7611%, resulting in an additional $160.0 million of borrowing base availability under~~derivative contracts at March 1, 2022. When aggregating multiple contracts, the ~~EEH Credit Agreement.~~

~~Impairments to Oil~~weighted average contract price is disclosed.

We had the following contractual obligations and commitments as of December 31, ~~2017:~~

(In thousands)

2018

2019

2020

2021

2022

Thereafter

Debt ⁽¹⁾

$
33

$
—

$
—

$
—

$
25,000

$
—

Derivative liabilities

11,805

1,826

—

—

—

—

Asset retirement obligations

310

—

36

—

374

1,497

Gas contracts ⁽²⁾

1,643

1,643

1,647

680

—

—

Office leases

854

723

—

—

—

—

Total

$
14,645

$
4,192

$
1,683

$
680

$
25,374

$
1,497

~~(1)~~

~~2018 amount represents interest payable under the EEH Credit Agreement as of December 31, 2017.~~

2022:

~~(2)~~

We have a non-cancelable fixed cost agreement of $1.6 million per year through 2021 to reserve pipeline capacity of 10,000 MMBtu per day for gathering and processing related to certain Eagle Ford assets in south Texas through 2021.


(In thousands)	2023		2024		2025		2026		2027		Thereafter
Debt (1)	$	10,995	$	—	$	—	$	—	$	1,053,879	$	—
Derivative liabilities	14,053		—		—		—		—		—
Asset retirement obligations	948		526		—		—		39		29,045

Office leases	1,138		1,160		868		1,052		961		327
Automobile leases	907		724		200		—		—		—
Total	$	28,042	$	2,410	$	1,068	$	1,052	$	1,054,879	$	29,372

(1)2023 amount represents accrued interest on long-term debt as of December 31, 2022.

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 material 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.

64

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:

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, ~~2017.~~2022. 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.

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.

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.

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.

The Company recognized stock-based compensation expense associated with restricted stock units, which include both time- and performance-based awards. The Company accounts for forfeitures of equity-based incentive awards as they occur. Stock-based compensation expense related to time-based restricted stock units is based on the price of the Class A common stock, $0.001 par value per share of Earthstone (“Class A Common Stock”), on the grant date and recognized over the vesting period using the straight-line method. The Company classifies grants to be settled in shares as equity awards and awards to be settled in cash a liability awards. The Company accounts for these awards based on a grant date Monte Carlo Simulation pricing model, which calculates multiple potential outcomes for an award and establishes fair value based on the most likely outcome, and is recognized over the vesting period using the straight-line method. The fair value of the liability awards is updated on a quarterly basis.

We are a U.S. company operating ~~primarily~~ in Texas and New Mexico, as of December 31, ~~2017,~~2022, 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.

~~Following the closing of the Bold Transaction, we continue to record an income tax provision consistent with our status as a corporation.~~

Our corporate structure requires the filing of two separate consolidated U.S. Federal income tax returns and one Canadian income tax return resulting from ~~the~~Earthstone’s acquisition of Lynden ~~Arrangement~~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. ~~Following the Bold Transaction,~~ 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 2021 results were reported on the U.S. Return of Partnership Income (Form 1065) and reported to EEH through Schedule K-1 (Form 1065). As IRM was treated as a Partnership, for federal and state income tax purposes, it was not subject to income taxes at the federal level. At the state level, IRM only operated in Texas and was subject to the Texas Margin Tax. On December 31, 2021, IRM was merged into another wholly owned subsidiary of EEH and no longer has statutory reporting requirements.

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, ~~2017~~2022 and ~~2016, the Company has~~2021, we recorded a valuation allowance for ~~its~~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, 2017, 2016 or 2015.

On December 22, 2017, the United States enacted tax reform legislation commonly known as the TCJA, resulting in significant modifications to existing law. Our consolidated financial statements for the year ended December 31, 2017, reflect certain effects of the TCJA, which includes ~~the federal corporate income tax rate reduction~~ to 21%. Consistent with Staff Accounting Bulletin No. 118 issued by the SEC, which provides for a measurement period of one year from the enactment date to finalize the accounting for effects of the TCJA, the Company provisionally recorded income tax expense of $7.8 million related to the TCJA. In accordance with SEC guidance, provisional amounts may be refinedFebruary 15, 2022, as a result of ~~additional guidance from, and interpretations by, U.S. regulatory and standard-setting bodies, and changes in assumptions. In~~ the ~~subsequent period, provisional amounts will be adjusted for the effects, if any, of interpretative guidance issued after December 31, 2017, by the U.S. Department~~completion of the ~~Treasury. The effects~~Chisholm Acquisition, which included the issuance of 19,417,476 shares of our Class A Common Stock, a limitation was triggered under Section 382 of the ~~TCJA may be subject to changes for items that were previously reported~~Internal Revenue Code of 1986, as ~~provisional amounts, as well as any element of the TCJA for which a provisional estimate could not be made, and such changes could be material.~~

~~The Company has made provisional computations of~~amended (the “Code”). We are currently assessing the impact of the ~~TCJA as provided for under SAB 118, including transition~~limitation on both our NOL and our deferred tax on the mandatory deemed repatriation of foreign earnings and executive compensation limitations under Internal Revenue Code Section 162(m), among others. The Internal Revenue Service is expected to issue additional guidance clarifying provisions of the Act. As additional guidance is issued one or more of the provisional amounts may change.

asset.

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

We are exposed to various risks including energy commodity price risk. When oil, natural gas and natural gas ~~liquids~~liquid prices decline significantly our ability to finance our capital budget and operations may be adversely impacted. We expect energy prices to remain volatile and unpredictable. Our hedging activities consist of derivative instruments entered into in order to hedge against changes in oil and natural gas prices through the use of fixed price ~~swap agreements.~~swaps, basis swaps, costless collars and deferred premium put options. Swaps exchange floating price risk in the future for a fixed price at the time of the hedge.

~~In connection with~~ Costless collars set both a maximum (sold ceiling) and a minimum (bought floor) future price. A deferred premium put option represents a bought floor except, unlike a standard put option, the ~~closing~~premium is not paid until the expiration of the ~~Bold Transaction on May 9 2017, all oil and natural gas derivative contracts were novated to EEH.~~ option.

We have entered into a series of derivative instruments to hedge a ~~significant~~ portion of our expected oil and natural gas production through December 31, ~~2019~~.2024. Typically, these derivative instruments require payments to (receipts from) counterparties based on specific indices as required by the derivative agreements. Although not risk free, we believe these instruments reduce our exposure to oil and natural gas price fluctuations and, thereby, allow us to achieve a more predictable cash flow.

The following is a summary of our open oil and natural gas derivative contracts as of December 31, ~~2017:~~

Period

Commodity

Volume
(Bbls / MMBtu)

Price
($/Bbl / $/MMBtu)

2018

Crude Oil Swap

1,483,250

$
51.38

2018

Crude Oil Basis Swap⁽¹⁾

602,250

$
(0.15
)
2019

Crude Oil Swap

547,500

$
52.32

2018

Natural Gas Swap

810,000

$
3.066

2022:

~~(1)~~

Period Commodity Volume
(Bbls / MMBtu) Price
($/Bbl / $/MMBtu)
2023 Crude Oil Swap 1,642,500 $76.94
2023 Crude Oil Basis Swap(1) 9,488,500 $0.92
2023 Natural Gas Swap 3,670,000 $3.52
2023 Natural Gas Basis Swap(2) 51,100,000 $(1.67)
2024 Natural Gas Basis Swap(2) 36,600,000 $(1.05)

(1)The basis differential ~~price is between Midland – WTI and the NYMEX – WTI~~

~~In January 2018, we entered into additional fixed~~ price ~~oil~~is between WTI Midland Argus Crude and ~~natural gas swap agreements, hedging an additional 365,000 Bbls of 2019 oil production at a~~the WTI NYMEX.

Changes in fair value of commodity derivative instruments are reported in earnings in the period in which they occur. Our open commodity derivative instruments were in a net liability position with a fair value of ~~$13.4~~$26.4 million at December 31, ~~2017.~~2022. Based on the published commodity futures price curves for the underlying commodity as of December 31, ~~2017,~~2022, a 10% increase in per unit commodity prices would cause the total fair value of our commodity derivative financial instruments to decrease by approximately ~~$12.3~~$1.1 million to an overall net ~~liability~~asset position of ~~$25.7~~$25.3 million. A 10% decrease in per unit commodity prices would cause the total fair value of our commodity derivative financial instruments to increase by approximately ~~$11.5~~$1.1 million to an overall net ~~liability~~asset position of ~~$1.9~~$27.5 million. There would also be a similar increase or decrease in (Loss) gain on derivative contracts, net in the Consolidated Statements of Operations.

Because the information above included only those exposures that existed at December 31, ~~2017,~~2022, it does not consider those exposures or positions which could arise after that date. As a result, our ultimate realized gain or loss with respect to interest rate and commodity price fluctuations will depend on the exposures that arise during future periods.

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.

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:

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.

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, ~~2017,~~2022, which is included herein.

There have not been any changes in our internal control over financial reporting during the quarter ended December 31, ~~2017~~2022 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

None.

Not applicable.

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 ~~2018~~ Proxy Statement, which will be filed with the SEC not later than 120 days subsequent to December 31, ~~2017.~~

2022.

The information required by this item is incorporated herein by reference to the ~~2018~~ Proxy Statement, which will be filed with the SEC not later than 120 days subsequent to December 31, ~~2017.~~

2022.

The information required by this item is incorporated herein by reference to the ~~2018~~ Proxy Statement, which will be filed with the SEC not later than 120 days subsequent to December 31, ~~2017.~~

2022.

The information required by this item is incorporated herein by reference to the ~~2018~~ Proxy Statement, which will be filed with the SEC not later than 120 days subsequent to December 31, ~~2017.~~

2022.

The information required by this item is incorporated herein by reference to the ~~2018~~ Proxy Statement, which will be filed with the SEC not later than 120 days subsequent to December 31, ~~2017.~~

2022.

Earthstone Energy, Inc., a Delaware corporation (“Earthstone” and together with its consolidated subsidiaries, the “Company”), is a growth-oriented independent oil and natural gas development and production company. In addition, the Company is active in corporate mergers and the acquisition of oil and natural gas properties that have production and future development opportunities. The Company’s operations are all in the up-stream segment of the oil and natural gas industry and all its properties are onshore in the United States.

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 Energy Corp., a corporation organized under the laws of British Columbia (“Lynden Corp”), and Lynden Corp’s wholly-owned consolidated subsidiary, Lynden USA Inc.~~, a Utah corporation~~ (“Lynden US”) ~~and also~~, collectively own a ~~member of EEH,~~75.5% interest in EEH. The Company consolidates the financial results of EEH and ~~records~~presents a noncontrolling interest in the Consolidated Financial Statements representing the economic interests of ~~EEH's~~EEH’s members other than Earthstone and Lynden US.

Certain prior period amounts have been reclassified to conform to current period presentation within the Consolidated Financial Statements. Prior period Re-engineering and workovers in the Consolidated Statements of Operations have been reclassified from its own line item and included in Lease operating expenses, within Operating Costs and Expenses, to conform to current period presentation. This reclassification had no effect on Loss from operations or any other subtotal in the Consolidated Statements of Operations.

~~Bold Contribution Agreement~~

~~On May 9, 2017, Earthstone completed~~ ~~a contribution agreement dated as of November 7, 2016 and as amended on March 21, 2017 (the “Bold Contribution Agreement”),~~ by and among Earthstone, EEH, Lynden US, Lynden USA Operating, LLC, a Texas limited liability company (“Lynden Op”), Bold Energy Holdings, LLC, a Texas limited liability company (“Bold Holdings”), and Bold Energy III LLC, a Texas limited liability company (“Bold”). The purposeEach of the Bold Contribution Agreement was to provide for, among other things described below, the business combination between Earthstone and Bold, which owned significant developed and undeveloped oil and natural gas properties in the Midland Basinoutstanding shares of ~~Texas (the “Bold Transaction”).~~

The Bold Transaction was structured in a manner commonly known as an “Up-C.” Under this structure and the Bold Contribution Agreement, (i) Earthstone recapitalized its common stock into two classes – Class A common stock, $0.001 par value per share of Earthstone (the “Class A Common Stock”), ~~and~~has a corresponding unit of limited liability company interests denominated as a common unit in EEH (an “EEH Unit”). Each of the outstanding shares of Class B common stock, $0.001 par value per share of Earthstone (the “Class B Common Stock”), has a corresponding EEH Unit and ~~all~~collectively represent the noncontrolling interests in the Consolidated Financial Statements.

At any time, at the holder’s discretion, a holder of ~~Earthstone’s existing outstanding common stock, $0.001 par value per~~an EEH Unit may receive a share ~~(the “Common Stock”), was recapitalized on a one-for-one basis for~~of Class A Common Stock ~~(the “Recapitalization”); (ii) Earthstone transferred all of its membership interests~~ in ~~Earthstone Operating, LLC, Sabine River Energy, LLC, EF Non-Op, LLC~~exchange for an EEH Unit and ~~Earthstone Legacy Properties, LLC (formerly Earthstone GP, LLC) and $36,071 in cash from the sale~~a corresponding share of Class B Common Stock, ~~to Bold Holdings (collectively,~~resulting in the ~~“Earthstone Assets”) to~~immediate cancellation of both the EEH in exchange for 16,791,296 membership units of EEH (the “EEH Units”); (iii) Lynden US transferred all of its membership interests in Lynden Op to EEH in exchange for 5,865,328 EEH Units; (iv) Bold Holdings transferred all of its membership interests in Bold to EEH in exchange for 36,070,828 EEH UnitsUnit and ~~purchased 36,070,828 shares~~share of Class B Common Stock ~~issued by~~exchanged. As of December 31, 2022, outstanding common shares of Earthstone, ~~for $36,071; and (v) Earthstone granted an aggregate~~along with the equal number of ~~150,000 fully vested~~corresponding outstanding EEH Units, were approximately 139.8 million, consisting of 105.5 million shares of Class A Common Stock under Earthstone’s 2014 Long-Term Incentive Plan, as amended (the ��2014 Plan”), to certain employees of Bold. Each EEH Unit, together with one share of Class B Common Stock, are convertible into one share of Class A Common Stock.

~~Upon closing of the Bold Transaction on May 9, 2017, Bold Holdings owned approximately 61.4% of the outstanding shares of Class A Common Stock, on a fully diluted, as converted basis. The EEH Units~~ and ~~the~~34.3 million shares of Class B Common ~~Stock issued~~Stock.

Noncontrolling Interest represents EEH Units held by members of EEH other than Earthstone and Lynden US and is presented as a component of equity in the Consolidated Balance Sheets as of December 31, 2022 and 2021, as well as an adjustment to ~~Bold Holdings were not registered under~~Net income in the ~~Securities Act~~Consolidated Statements of ~~1933, as amended (the “Securities Act”), but were issued by~~Operations for the years ended December 31, 2022 and 2021. Pursuant to governing EEH agreements, the noncontrolling members have no direct participation in the operations of EEH.

Earthstone consolidates the financial results of EEH and ~~Earthstone~~its subsidiaries, and presents a noncontrolling interest for the economic interest in ~~reliance on the exemption provided under Section 4(a)(2) of the Securities Act.~~

On May 9, 2017, the closing sale price of the Class A Common Stock was $13.58 per share. On May 10, 2017, the Class A Common Stock was uplisted from the NYSE American, LLC (formerly the NYSE MKT) (the “NYSE American”) to the New York Stock Exchange (the “NYSE”) where it is listed under the symbol “ESTE.”

~~On May 9, 2017, in connection with the closing of the Bold Transaction,~~ Earthstone EnCap Investments L.P. (“EnCap”), Oak Valley Resources, LLC (“OVR”), and Bold Holdings entered into a voting agreement (the “Voting Agreement”), pursuant to which EnCap, OVR, and Bold Holdings agreed not to vote any shares of Class A Common Stock or Class B Common Stock held by ~~them in favor~~members of ~~any action, or take any action that would in any way alter the composition of the board of directors of~~EEH other than Earthstone (the “Board”) from its composition immediately following the closing of the Bold Transaction as long as the Voting Agreement is in effect. The Voting Agreement terminates on the earlier of (i) the fifth anniversary of the closing date of the Bold Contribution Agreement and ~~(ii) the date upon which EnCap, OVR~~Lynden US, and ~~Bold Holdings collectively own, of record and beneficially, less than 20% of Earthstone’s~~represented by outstanding ~~voting stock.~~

~~F-8~~

~~EARTHSTONE ENERGY, INC.~~

~~NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)~~

Pursuant to the terms of the Bold Contribution Agreement, at the closing of the Bold Transaction, Earthstone, Bold Holdings, and the unitholders of Bold Holdings entered into a registration rights agreement (the “Registration Rights Agreement”) relating to the shares of Class A Common Stock issuable upon the exchange of the EEH Units and Class B Common Stock held by Bold Holdings or its unitholders. In accordance with the Registration Rights Agreement, Earthstone filed a registration statement (the “Registration Statement”) with the Securities and Exchange Commission (the “SEC”) to permit the public resale of the shares of Class A Common Stock issued by Earthstone to Bold Holdings or its unitholders in connection with the exchange of Class B Common Stock and EEH Units in accordance with the terms of the First Amended and Restated Limited Liability Company Agreement of EEH (the “EEH LLC Agreement”). On October 18, 2017, the Registration Statement was declared effective by the SEC.

The Bold Transaction was recorded in accordance with Financial Accounting Standards Board (“FASB”) Accounting Standards Codification (“ASC”) Topic 805, Business Combinations, and is consolidated in these financial statements in accordance with FASB ASC Topic 810, Consolidation, which requires the recording of aStock. Net income attributable to noncontrolling interest ~~component~~in the Consolidated Statements of Operations for the year ended December 31, 2022 represents the portion of net income ~~(loss), as well as a~~attributable to the economic interest in the Company held by members of EEH other than Earthstone and Lynden US. The noncontrolling interest ~~component within equity, including changes to additional paid-in capital to reflect the noncontrolling interest within equity~~ in the Consolidated Balance Sheet as of December 31, ~~2017 at~~2022 represents the portion of net assets of the Company attributable to members of EEH other than Earthstone and Lynden US.

The following table presents the changes in noncontrolling ~~interest’s respective membership~~ interest ~~in EEH.~~

for the year ended December 31, 2022:

The ~~consolidated financial statements~~Consolidated Financial Statements include the accounts and balances of the Company and have been prepared in accordance with accounting principles generally accepted in the United States (“GAAP”). All intercompany accounts and transactions, including revenues and expenses, are eliminated in consolidation.

The preparation of the Company’s ~~consolidated financial statements~~Consolidated Financial Statements in conformity with GAAP requires the Company’s management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities, if any, at the date of the ~~consolidated financial statements~~Consolidated Financial Statements and the reported amounts of revenues and expenses during the respective reporting periods then ended.

Although management believes these estimates are reasonable, actual results may differ from estimates and assumptions of future events and these revisions could be material. Future production may vary materially from estimated oil and natural gas proved reserves. Actual future prices may vary significantly from price assumptions used for determining proved reserves and for financial reporting.

Accounts receivable include estimated amounts due from crude oil, natural gas, and natural gas liquids purchasers, other operators for which the Company holds an interest, and from non-operating working interest owners. Accrued crude oil, natural

gas, and natural gas liquids sales from purchasers and operators consist of accrued revenues due under normal trade terms, generally requiring payment within 60 days of production.

For receivables from joint interest owners, the Company typically has the ability to withhold future revenue disbursements to recover any non-payment of joint interest billings.

An allowance for doubtful accounts is established based on reviews of individual customer accounts, recent loss experience, current economic conditions, and other pertinent factors. Accounts deemed uncollectible are charged to the allowance.

Provisions for bad debts and recoveries on accounts previously charged off are added to the allowance. The Company routinely assesses the recoverability of all material trade receivables and other receivables to determine their collectability. Allowance for uncollectible accounts receivable was ~~$0.1~~$0.02 million at and ~~$0.2~~$0.02 million at December 31, ~~2017~~2022 and ~~2016,~~2021, respectively.

~~F-9~~

~~EARTHSTONE ENERGY, INC.~~

~~NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)~~

The Company utilizes derivative instruments in order to manage exposure to ~~commodity price risk~~risks associated with ~~future oil~~fluctuating commodity prices and ~~natural gas production.~~interest rates. The Company recognizes all derivatives as either assets or liabilities, measured at fair value, and recognizes changes in the fair value of derivatives in current earnings. The Company has elected to not designate any of its positions under the hedge accounting rules. Accordingly, these derivative contracts are mark-to-market and any changes in the estimated values of derivative contracts held at the balance sheet date are recognized in (Loss) gain on derivative contracts, net in the Consolidated Statements of Operations as unrealized gains or losses on derivative contracts. Realized gains or losses on derivative contracts are also recognized in (Loss) gain on derivative contracts, net in the Consolidated Statements of Operations.

Operating segments are ~~defined under FASB ASC Topic 280, Segment Reporting, 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~~the Company’s organization and management, ~~we have~~it has only one reportable operating segment, which is oil and natural gas exploration and production. ~~We consider drilling rig services ancillary to our oil and natural gas exploration and producing activities and manage these services to support such activities.~~

The Company has no elements of comprehensive income other than net income.

Asset retirement obligations associated with the retirement of long-lived assets are recognized as liabilities with an increase to the carrying amounts of the related long-lived assets in the period incurred. The cost of the asset, including the asset retirement cost, is depreciated over the useful life of the asset. Asset retirement obligations are recorded at estimated fair value, measured by reference to the expected future cash outflows required to satisfy the retirement obligations discounted at the Company’s

The Company accounts for ~~the acquisition~~its acquisitions of oil and gas properties not commonly controlled ~~based on the requirements of FASB ASC~~in accordance with Financial Accounting Standards Board (“FASB”) Accounting Standards Codification (“ASC”) Topic 805, Business Combinations, which, among other things, requires the Company to determine if an ~~acquiring entity to recognize~~asset or a business has been acquired. If the Company determines an asset(s) has been acquired, the asset(s) acquired, as well as any liabilities assumed, are measured and recorded at the acquisition date cost. If the Company determines a business has been acquired, the assets acquired and liabilities assumed are measured and recorded at their fair ~~value under~~values as of the acquisition ~~method~~date, recording goodwill for amounts paid in excess of ~~accounting, provided such assets~~fair value.

The Company’s revenues are comprised solely of revenues from customers and ~~liabilities qualify for acquisition accounting under~~include the ~~standard. The Company accounts for property acquisitions~~sale of ~~proved developed~~ oil, ~~and gas properties as business combinations.~~

~~F-10~~

~~EARTHSTONE ENERGY, INC.~~

~~NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)~~

~~Revenue Recognition~~

~~Oil,~~ natural gas and natural gas ~~liquids revenues represent income~~liquids. The Company believes that the disaggregation of revenue into these three major product types, as presented in the Consolidated Statements of Operations, appropriately depicts how the nature, amount, timing and uncertainty of revenue and cash flows are affected by economic factors based on its single geographic region. Revenues are recognized when the recognition criteria of ASC 606 “Revenue from Contracts with Customers,” (“ASC 606”) are met, which generally occurs at a point in time when production is sold to a purchaser at a determinable price, delivery has occurred, control has transferred and collection of the ~~production and~~revenue is probable. The Company fulfills its performance obligations under its customer contracts through delivery of oil, natural gas and natural gas liquids and revenues are recorded on a monthly basis and the Company receives payment from one to three months after delivery. Generally, each unit of product represents a separate performance obligation. The prices received for oil, natural gas and natural gas liquids sales under the Company’s contracts are generally derived from stated market prices which are then adjusted to reflect deductions including transportation, fractionation and processing. As a result, revenues from the sale of oil, natural gas and natural gas liquids will decrease if market prices decline. The sales of oil, natural gas and natural gas liquids, as presented on the Consolidated Statements of Operations, represent the Company’s share of revenues net of ~~royalties. Revenues~~royalties and excluding revenue interests owned by others. When selling oil, natural gas and natural gas liquids on behalf of royalty or working interest owners, the Company is acting as an agent and thus reports the revenue on a net basis. To the extent actual volumes and prices of oil and natural gas sales are unavailable for a given reporting period because of timing or information not received from third parties, the expected sales volumes and prices for those properties are estimated and recorded. Variances between the Company’s estimated revenue and actual payment are recorded in the month the payment is received. Historically, however, differences have been insignificant.

At the end of each month when the performance obligation is satisfied, the variable consideration can be reasonably estimated and amounts due from customers are recorded in “Accounts receivable: oil, natural gas, and natural gas liquids revenues” in the Consolidated Balance Sheets. As of December 31, 2022 and 2021, amounts receivable from contracts with customers were $161.5 million and $50.6 million, respectively. Taxes assessed by governmental authorities on oil, natural gas and natural gas liquid sales are presented separately from such revenues in the Consolidated Statements of Operations.

Oil production is transported from the wellhead to tank batteries or delivery points through flow-lines or gathering systems. Purchasers of the oil take delivery at (i) the tank batteries and transport the oil by truck, or (ii) at a pipeline delivery point and the Company collects a market price, net of pricing differentials. Revenue is recognized when control transfers to the purchaser at the net price received by the Company. Starting in October 2019, certain of the Company’s oil sales activity involves buy/sell arrangements that effect a change in location with required repurchase of oil at a delivery point. Because the Company acts as the agent in these transactions, the buy/sell activity is recorded on a net basis and the residual transportation fee is included in Lease operating expenses in the Consolidated Statements of Operations.

Under the Company’s natural gas sales arrangements, the purchaser takes control of wet gas at a delivery point near the wellhead or at the inlet of the purchaser’s processing facility. The purchaser gathers and processes the wet gas and remits proceeds to the Company for the resulting natural gas and natural gas liquid sales. Based on the nature of these arrangements, the Company is the agent and the purchaser is the Company’s customer, thus, the Company recognizes natural gas and natural gas liquid sales based on the net amount of proceeds received from the purchaser.

The Company recognizes revenue for all oil, natural gas and natural gas liquid sold to purchasers regardless of whether the sales are proportionate to the Company’s ownership interest in the property. Production imbalances are recognized ~~when production~~as a liability to the extent an imbalance on a specific property exceeds the Company’s share of remaining proved oil, natural gas liquid and natural gas reserves. The Company is ~~sold~~also subject to ~~a purchaser~~natural gas pipeline imbalances, which are recorded as accounts receivable or payable at ~~a fixed or determinable price, delivery has occurred, title has been transferred, and collectability~~values consistent with contractual arrangements with the owner of the ~~revenue is probable. The Company follows the sales method of accounting for gas imbalances.~~pipeline. The Company had no ~~significant gas~~ imbalances as of December 31, ~~2017, 2016,~~2022 or ~~2015.~~

2021.

Under the Company’s product sales contracts, the Company invoices customers once performance obligations have been satisfied, at which point payment is unconditional. Accordingly, the Company’s product sales contracts do not give rise to contract assets or liabilities under ASC 606.

Substantially all of the Company’s product sales are short-term in nature, with a contract term of one year or less. For these contracts, the Company has utilized the practical expedient in ASC 606 which exempts the Company from the requirements to disclose the transaction price allocated to remaining performance obligations if the performance obligation is part of a contract that has an original expected duration of one year or less.

For the Company’s product sales that have a contract term greater than one year, the Company has utilized the practical expedient in ASC 606 which states the Company is not required to disclose the transaction price allocated to remaining performance obligations if the variable consideration is allocated entirely to a wholly unsatisfied performance obligation. Under these contracts, each unit of product generally represents a separate performance obligation; therefore, future volumes are wholly unsatisfied, and disclosure of the transaction price allocated to remaining performance obligations is not required.

The Company records revenue in the month that product is delivered to the purchaser. Settlement statements for certain natural gas and natural gas liquids sales, however, may not be received for 30 to 90 days after the date the product is delivered, and as a result the Company is required to estimate the amount of product delivered to the purchaser and the price that will be received for the sale of the product. In these situations, the Company records the differences between its estimates and the actual amounts received for product sales in the month that payment is received from the purchaser. Any identified differences between the Company’s revenue estimates and actual revenue received have historically been insignificant. For the years ended December 31, 2022 and 2021, revenue recognized in the reporting period related to performance obligations satisfied in prior reporting periods was not material.

Credit risk represents the actual or perceived financial loss that the Company would record if its purchasers, operators, or counterparties failed to perform pursuant to contractual terms.

The purchasers of the Company’s oil, natural gas, and natural gas liquids production consist primarily of independent marketers, major oil and natural gas companies and natural gas pipeline companies. Historically, the Company has not experienced any significant losses from uncollectible accounts. In ~~2017,~~the year ended December 31, 2022, three purchasers accounted for ~~18%~~21%, ~~14%~~20% and 14%, respectively, of the Company’s oil, natural gas, and natural gas liquids revenues. In ~~2016,~~the year ended December 31, 2021, two purchasers accounted for ~~41%~~34% and ~~19%~~13%, respectively, of the Company’s oil, natural gas, and natural gas liquids revenues. In ~~2015, one purchaser~~the year ended December 31, 2020, three purchasers accounted for ~~62%~~32%, 15% and 12%, respectively, of the Company’s oil, natural gas, and natural gas liquids revenues. No other purchaser accounted for 10% or more of the Company’s oil, natural gas, and natural gas liquids revenues during ~~2017, 2016, and 2015.~~the years ended December 31, 2022, 2021 or 2020. Additionally, at December 31, ~~2017, three~~2022, four purchasers accounted for ~~20%~~21%, ~~13%~~19% , 18% and ~~12%~~14%, respectively, of the Company’s oil, natural gas and natural gas liquids receivables. At December 31, ~~2016, two~~2021, three purchasers accounted for ~~28%~~26%, 21% and 12%, respectively, of the Company’s oil, natural gas, and natural gas liquids receivables. No other purchaser accounted for 10% or more of the Company’s oil, natural gas, and natural gas liquids receivables at December 31, ~~2017~~2022 and ~~2016.~~

2021.

The Company holds working interests in oil and natural gas properties for which a ~~third party~~third-party serves as operator. The operator sells the oil, natural gas, and ~~NGLs~~natural gas liquids to the purchaser, collects the cash, and distributes the cash to the Company. In ~~2017, 2016 and 2015,~~the year ended December 31, 2022, one operator distributed ~~10%, 19% and 12%, respectively,~~8% of the Company’s oil, natural gas and natural gas liquids revenues. ~~No other~~In the year ended December 31, 2021 one operator ~~accounted for 10% or more~~distributed 13% of the Company’s oil, natural gas and natural gas liquids ~~revenues during 2017, 2016,~~revenues. In the year ended December 31, 2020, one operator distributed 15% of the Company’s oil, natural gas and ~~2015.~~

natural gas liquids revenues.

The derivative instruments of the Company are with a small number of counterparties and, from time-to-time, may represent material assets in the Consolidated Balance Sheets. It is our policy to enter into derivative contracts only with counterparties that are creditworthy financial institutions deemed by management as competent and competitive. At December 31, ~~2017 and 2016,~~2022, the Company had noa net derivative ~~contracts that were in~~asset position of $26.4 million. At December 31, 2021, the Company had a ~~material asset position.~~

net derivative liability position of $44.4 million.

The Company regularly maintains its cash in bank deposit accounts. Balances held by the Company at its banks typically exceed Federal Deposit Insurance Corporation (“FDIC”) insurance coverage and, as a result, there is a concentration of credit risk related to the amounts of deposit in excess of FDIC insurance coverage.

The Company is a U.S. company operating ~~primarily~~ in Texas and New Mexico, as of December 31, ~~2017, as well as~~2022, and includes one foreign legal entity, Lynden Corp, which is a Canadian company. Consequently, the Company’s tax provision is based upon the tax laws and rates in effect in the applicable jurisdiction in which its 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,~~Consolidated Financial Statements, the Company is 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. The Company’s effective tax rate for financial statement purposes will continue to fluctuate from year to year as its operations are conducted in different taxing jurisdictions.

~~Following the closing of the Bold Transaction, the~~

The Company ~~continues to record~~records an income tax provision consistent with its status as a corporation. The Company’s 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 May 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. ~~Following the Bold Transaction,~~ 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.

~~F-11~~

~~EARTHSTONE ENERGY, INC.~~

~~NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)~~

The Company’s deferred tax expense or benefit represents the change in the balance of deferred tax assets or liabilities reported in the 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, ~~2017~~2022 and ~~2016,~~2021, the Company has recorded a valuation allowance for its deferred tax assets in the Consolidated Balance Sheets.

The Company applies 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.~~Consolidated Financial Statements. It requires that the Company recognize in the ~~consolidated financial statements~~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. The Company’s tax positions related to its pass-through status and state income tax liability, including deductibility of expenses, have been reviewed by the Company’s management and they believe those positions would more likely than not be sustained upon examination. Accordingly, the Company has not recorded an income tax liability for uncertain tax positions at December 31, ~~2017, 2016~~2022 or ~~2015.~~

On December 22, 2017, the United States enacted tax reform legislation commonly known as the Tax Cuts and Jobs Act (the “TCJA”), resulting in significant modifications to existing law. Our consolidated financial statements for the year ended December 31, 2017, reflect certain effects of the TCJA, which includes ~~the federal corporate income tax rate reduction~~ to 21%. Consistent with Staff Accounting Bulletin No. 118 issued by the SEC, which provides for a measurement period of one year from the enactment date to finalize the accounting for effects of the TCJA, the Company provisionally recorded income tax expense of $7.8 million related to the TCJA. In accordance with SEC guidance, provisional amounts may be refined as a result of additional guidance from, and interpretations by, U.S. regulatory and standard-setting bodies, and changes in assumptions. In the subsequent period, provisional amounts will be adjusted for the effects, if any, of interpretative guidance issued after December 31, 2017, by the U.S. Department of the Treasury. The effects of the TCJA may be subject to changes for items that were previously reported as provisional amounts, as well as any element of the TCJA for which a provisional estimate could not be made, and such changes could be material.

The Company has made provisional computations of the impact of the TCJA as provided for under SAB 118, including transition tax on the mandatory deemed repatriation of foreign earnings and executive compensation limitations under Internal Revenue Code Section 162(m), among others. The Internal Revenue Service is expected to issue additional guidance clarifying provisions of the Act. As additional guidance is issued one or more of the provisional amounts may change.

2021.

accounting for ~~all contracts with customers to improve comparability within industries, across industries~~contract modifications and across capital markets. This new revenue standard contains principles that an entity will apply to determine the measurement of revenue and timing of when it is recognized. The underlying principle is that an entity will recognize revenue to depict the transfer of goods or services to customers at an amount that the entity expects to be entitled to in exchange for those goods or services. The two permitted transition methods under the new standard are the full retrospective method, in which case the standard would be applied to each prior reporting period presented, or the modified retrospective method, in which case the cumulative effect of applying the standard would be recognized at the date of initial application. The new standard is now effective prospectively for reporting periods beginning on or after December 15, 2017.hedge accounting. The Company ~~has completed~~amended its ~~evaluation of~~credit facility on January 30, 2022, which, among other things, provided mechanics relating to the ~~new standard and will adopt the new standard, as required, beginning with the first quarter of 2018, and does~~transition from LIBOR to a benchmark replacement rate. The transition from LIBOR did not ~~expect the adoption to~~ have a material impact on its Consolidated Financial Statements. The Company has elected to use the modified retrospective method for adoption and has updated its related internal control documentation, processes and controls to conform to the new standard.

~~F-12~~

~~EARTHSTONE ENERGY, INC.~~

~~NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)~~

~~Leases~~ ~~– In February 2016, the FASB issued updated guidance on accounting for leases.~~ The update requires that a lessee recognize in the statement of financial position a liability to make lease payments and a right-of-use asset representing its right to use the underlying asset for the lease term. For leases with a term of 12 months or less, a lessee is permitted to make an accounting policy election by class of underlying asset not to recognize lease assets and lease liabilities. Similar to current guidance, the update continues to differentiate between finance leases and operating leases; however, this distinction now primarily relates to differences in the manner of expense recognition over time and in the classification of lease payments in the statement of cash flows. The standards update is effective for interim and annual periods beginning after December 15, 2018 with early adoption permitted. Entities are required to use a modified retrospective adoption, with certain relief provisions, for leases that exist or are entered into after the beginning of the earliest comparative period in the financial statements when adopted. The Company expects to adopt this standards update, as required, beginning with the first quarter of 2019. ~~The Company is in the process of evaluating the impact, if any, of the adoption of this guidance on its Consolidated Financial Statements.~~

~~Statement of Cash Flows –~~ In August 2016, the FASB issued updated guidance that clarifies how certain cash receipts and cash payments are presented in the statement of cash flows. This update provides guidance on eight specific cash flow issues. The standards update is effective for interim and annual periods beginning after December 15, 2017, and should be applied retrospectively to all periods presented. The Company will adopt this update, as required, beginning with the first quarter of 2018, and does not expect the adoption to have a material impact on its Consolidated Statements of Cash Flows.

~~Business Combinations –~~ In January 2017, the FASB issued updated guidance that clarifies the definition of a business, which amends the guidance used in evaluating whether a set of acquired assets and activities represents a business. The guidance requires an entity to evaluate if substantially all of the fair value of the gross assets acquired is concentrated in a single identifiable asset or a group of similar identifiable assets; if so, the set of transferred assets and activities is not considered a business. As a result, acquisition fees and expenses will be capitalized to the cost basis of the property acquired, and the tangible and intangible components acquired will be recorded based on their relative fair values as of the acquisition date. The standard is effective for all public business entities for annual periods beginning after December 15, 2017. The Company will adopt this update, as required, beginning with the first quarter of 2018, and does not expect the adoption to have a material impact on its Consolidated Financial Statements.

~~Intangibles - Goodwill and Other –~~ In January 2017, the FASB issued updated guidance simplifying the test for goodwill impairment. The update eliminates Step 2 of the goodwill impairment test. Instead, an entity should perform its annual or interim goodwill impairment test by comparing the fair value of a reporting unit with its carrying amount. An entity should recognize an impairment charge for the amount by which the carrying amount exceeds the reporting unit’s fair value; however, the loss recognized should not exceed the total amount of goodwill allocated to that reporting unit. An entity still has the option to perform the qualitative assessment for a reporting unit to determine if the quantitative impairment test is necessary. The update is effective for annual and interim periods beginning after December 15, 2019 and early adoption is permitted for interim or annual goodwill impairment tests performed after January 1, 2017. The Company is in the process of evaluating the impact, if any, on its Consolidated Financial Statements.

~~Compensation – Stock Compensation –~~ In May 2017, the FASB issued updated guidance that provides clarity about which changes to the terms or conditions of a share-based payment award require an entity to apply modification accounting. The update is effective for annual periods beginning after December 15, 2017. The Company will adopt this update, as required, beginning with the first quarter of 2018, and does not expect the adoption to have a material impact on its Consolidated Financial Statements.

~~Note 3. Acquisitions and Divestitures~~

~~The Company accounts for its acquisitions that qualify as business combinations, under the acquisition method of accounting in accordance with FASB ASC Topic 805,~~ ~~Business Combinations~~, which, among other things, requires the assets acquired and liabilities assumed to be measured and recorded at their fair values as of the acquisition date. The initial accounting for acquisitions may not be complete and adjustments to provisional amounts, or recognition of additional assets acquired or liabilities assumed, may occur as additional information is obtained about the facts and circumstances that existed as of the acquisition dates.

~~Bold Transaction~~

~~On May 9, 2017, Earthstone completed the Bold Transaction~~ ~~described in~~ ~~Note 1. Organization and Basis of Presentation~~.

An allocation of the purchase price was prepared using, among other things, a reserve report prepared by qualified reserve engineers and priced as of the acquisition date. The following allocation is still preliminary with respect to final tax amounts and certain accruals and includes the use of estimates based on information that was available to management at the time these Consolidated Financial Statements were prepared.

~~F-13~~

~~EARTHSTONE ENERGY, INC.~~

~~NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)~~

~~The following table summarizes the consideration transferred, fair value of assets acquired and liabilities assumed (in thousands, except share and share price amounts~~):

Consideration:

Shares of Class A Common Stock issued pursuant to the Bold Contribution Agreement to certain employees of Bold

150,000

EEH Units issued to Bold Holdings

36,070,828

Total equity interest issued in the Bold Transaction

36,220,828

Closing per share price of Class A Common Stock as of May 9, 2017

$
13.58

Total consideration transferred ^{(1) (2)}

$
491,879

Fair value of assets acquired:

Cash and cash equivalents

$
2,355

Other current assets

10,078

Oil and gas properties ⁽³⁾

557,704

Amount attributable to assets acquired

$
570,137

Fair value of liabilities assumed:

Long-term debt ⁽⁴⁾

$
58,000

Current liabilities

17,042

Deferred tax liability

2,857

Noncurrent asset retirement obligations

359

Amount attributable to liabilities assumed

$
78,258

~~(1)~~

~~Consideration included 150,000 shares of Class A Common Stock recorded above based upon its fair value which was determined using the closing price of $13.58 per share on May 9, 2017.~~

~~(2)~~

Consideration was 36,070,828 EEH Units. Additionally, Bold Holdings purchased 36,070,828 shares of Class B Common Stock for $36,071. Each EEH Unit, together with one share of Class B Common Stock, is convertible into one share of Class A Common Stock. The fair value of the consideration was determined using the closing price of the Company’s Class A Common Stock of $13.58 per share on May 9, 2017.

~~(3)~~

The market assumptions as to the future commodity prices, projections of estimated quantities of oil and natural gas reserves, expectations for timing and amount of the future development and operating costs, projections of future rates of production, expected recovery rate and risk adjusted discount rates used by the Company to estimate the fair value of the oil and natural gas properties represent Level 3 inputs; see ~~Note 3. Fair Value Measurements, below.~~

~~(4)~~

~~Concurrent with the closing of the Bold Transaction, EEH repaid Bold’s outstanding borrowings of $58.0 million under its credit agreement.~~

~~F-14~~

~~EARTHSTONE ENERGY, INC.~~

~~NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)~~

The following unaudited supplemental pro forma condensed results of operations present consolidated information as though the Bold Transaction and the Bakken Sale (discussed below) had been completed as of January 1, 2016. The unaudited supplemental pro forma financial information was derived from the historical consolidated and combined statements of operations for Bold and Earthstone and adjusted to include: (i) depletion expense applied to the adjusted basis of the properties acquired and (ii) to eliminate non-recurring transaction costs directly related to the Bold Transaction that do not have a continuing impact on the Company’s operating results. These unaudited supplemental pro forma results of operations are provided for illustrative purposes only and do not purport to be indicative of the actual results that would have been achieved by the combined company for the periods presented or that may be achieved by the combined company in the future. Future results may vary significantly from the results reflected in this unaudited pro formaconsolidated financial ~~information (in thousands, except per share amounts~~):

statements.

The initial accounting for acquisitions and divestitures may not be complete and adjustments to provisional amounts, or recognition of additional assets acquired or liabilities assumed, may occur as additional information is obtained about the facts and circumstances that existed as of the acquisition dates.

On November 2, 2021, Earthstone, EEH and Foreland Investments LP, a Delaware limited partnership (“Foreland”), consummated the transactions contemplated in the Purchase and Sale Agreement dated as of September 30, 2021 by and among Earthstone, EEH and Foreland (the “Foreland Purchase Agreement”). At the closing of the Foreland Purchase Agreement, EEH acquired (the “Foreland Acquisition”) interests in oil and gas leases and related property of Foreland located in Irion County and Crockett County, Texas, for a purchase price consisting of: (i) $13.4 million in cash, net of customary purchase price adjustments, and (ii) 2,611,111 shares of Class A Common Stock.

Also, on November 2, 2021, Earthstone, EEH and BCC-Foreland LLC, a Delaware limited liability company (“BCC”), consummated the transactions contemplated in the Purchase and Sale Agreement dated as of September 30, 2021 by and among Earthstone, EEH and BCC (the “BCC Purchase Agreement”). At the closing of the BCC Purchase Agreement, EEH acquired (the “BCC Acquisition” and with the Foreland Acquisition, the “Foreland-BCC Acquisition”) certain well-bore interests and related equipment held by BCC that were part of a joint development agreement between Foreland, Foreland Operating, LLC, and BCC involving portions of the acreage covered by the Foreland Purchase Agreement for a purchase price of $20.5 million in cash, net of customary purchase price adjustments.

During the year ended December 31, 2022, the Company sold certain non-core properties for approximately $49.5 million in cash, resulting in net gains of approximately $13.9 million recorded in Gain on sale of oil and gas properties, net in the Consolidated Statements of Operations.

There were no material divestitures during the years ended December 31, 2021 or 2020.

During the year ended December 31, 2022, the Company recorded transaction costs of $8.2 million primarily due to legal, consulting and other fees related to the Chisholm Acquisition and certain divestiture transactions.

During the year ended December 31, 2021, the Company recorded transaction costs primarily due to legal, consulting and other fees of approximately $4.0 million related to the IRM Acquisition, $1.8 million related to the Chisholm Acquisition and $0.3 million related to other potential transactions, offset by net reimbursements of $1.2 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, 2020, the Company recorded transaction costs primarily due to legal, consulting and other fees of approximately $1.0 million related to the IRM Acquisition noted above and $0.3 million related to other potential transactions, offset by net reimbursements of $0.7 million related to the Bold Transaction.

FASB ASC Topic 820, defines fair value as the price that would be received to sell an asset, or paid to transfer a liability, in an orderly transaction between market participants at the measurement date. ASC Topic 820 provides a framework for measuring fair value, establishes a three-level hierarchy for fair value measurements based upon the transparency of inputs to the valuation of an asset or liability as of the measurement date and requires consideration of the counterparty’s creditworthiness when valuing certain assets.

The three-level fair value hierarchy for disclosure of fair value measurements defined by ASC Topic 820 is as follows:

A financial instrument’s level within the fair value hierarchy is based on the lowest level of any input that is significant to the fair value measurement. Where available, fair value is based on observable market prices or parameters or derived from such prices or

~~F-15~~

~~EARTHSTONE ENERGY, INC.~~

~~NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)~~

parameters. Where observable prices or inputs are not available, valuation models are applied. These valuation techniques involve some level of management estimation and judgment, the degree of which is dependent on the price transparency for the instruments or market and the instrument’s complexity. The Company reflects transfers between the three levels at the beginning of the reporting period in which the availability of observable inputs no longer justifies classification in the original level. There were no transfers between fair value hierarchy levels for the year ended December 31, ~~2017.~~

2022.

Derivative financial instruments are carried at fair value and measured on a recurring basis. The derivative financial instruments consist of fixed price swaps, basis swaps, costless collars and deferred premium put options for crude oil and natural ~~gas.~~gas and interest rate swaps. The Company’s commodity price hedges and interest rate swaps are valued based on a discounted future cash flow ~~model. The primary input for the model is~~models that are primarily based on published forward commodity price ~~curves. The swaps~~curves and published LIBOR forward curves; thus, these inputs are ~~also~~ designated as Level 2 within the valuation hierarchy.

The fair values of ~~commodity~~ derivative instruments in an asset ~~position~~positions include ~~a measure~~measures of counterparty nonperformance risk, and the fair values of ~~commodity~~ derivative instruments in a liability ~~position~~positions include ~~a measure~~measures of the Company’s nonperformance risk. These measurements were not material to the Consolidated Financial Statements.

Certain of our performance-based stock awards (“PSUs”) may be payable in cash. The Company classifies the awards that may be settled in cash as liability awards. These awards are valued quarterly utilizing the Monte Carlo Simulation pricing model, which calculates multiple potential outcomes for an award and establishes grant date fair value based on the most likely outcome. The inputs for the Monte Carlo model are designated as Level 2 within the valuation hierarchy. The share-based compensation liability related to the PSU liability awards is included in Accrued expenses and Other noncurrent liabilities in the Consolidated Balance Sheet as of December 31, 2022.

Other financial instruments include cash, accounts receivable and payable, and revenue royalties. The carrying amount of these instruments approximates fair value because of their short-term nature. The Company’s long-term debt obligation bears interest at floating market rates, therefore carrying amounts and fair value are approximately equal.

The Company applies the provisions of the fair value measurement standard on a non-recurring basis to its non-financial assets and liabilities, including oil and gas properties, goodwill, business combinations and ~~goodwill.~~asset retirement obligations. These assets and liabilities are not measured at fair value on an ongoing basis but are subject to fair value adjustments ~~only~~if events or changes in certain ~~circumstances.~~

~~Proved Oil~~circumstances indicate that adjustments may be necessary. Due to significant declines in commodity prices and ~~Natural Gas Properties~~

~~Proved~~global demand for oil and natural gas products resulting from the COVID-19 pandemic, the Company assessed the fair values of its oil and natural gas properties ~~are measured~~and goodwill resulting in non-cash impairment charges during the three months ended March 31, 2020. Since then, commodity prices have recovered and no other such triggering events that require further assessment were observed during the years ended December 31, 2022 and 2021.

The Class B Common Stock has been excluded, as its conversion would eliminate noncontrolling interest and Net income attributable to noncontrolling interest of $198.1 million for the year ended December 31, 2022, Net loss attributable to noncontrolling interest of ~~$32.2~~$26.0 million for the year ended December 31, 2021, and Net income attributable to noncontrolling interest of $15.9 million for the year ended December 31, 2020 would be added back to Net ~~loss~~income (loss) attributable to Earthstone Energy, Inc., for the years then ended, having no dilutive effect on Net ~~loss~~income (loss) per common share attributable to Earthstone Energy, Inc. For the ~~years~~year ended December 31, ~~2017 and 2016,~~2020, the Company excluded ~~105,422~~1.1 million and ~~52,844~~1.9 million shares, respectively, for the dilutive effect of restricted stock units and performance units in calculating diluted earnings per share as the effect was anti-dilutive due to the net loss incurred ~~these periods. For~~for the ~~year ended December 31, 2015, there were no restricted stock units issued or outstanding under the 2014 Plan.~~

period.

At December 31, ~~2017,~~2022 and 2021, there were ~~27,584,638~~105,547,139 and 53,467,307 shares of Class A Common Stock issued and ~~outstanding. On July 1, 2017,~~outstanding, respectively. During the year ended December 31, 2022, Earthstone ~~retired and returned the 15,357 shares~~issued a total of ~~treasury stock to authorized but unissued~~approximately 28.9 million shares of Class A Common ~~Stock.~~Stock in connection with the Chisholm Acquisition, Bighorn Acquisition and the Titus Acquisition, as well as approximately 25.2 million shares of Class A Common Stock upon conversion of the Series A Convertible Preferred Stock described below. During the ~~period January 1, 2017 through May 8, 2017, the Company~~year ended December 31, 2021, Earthstone issued ~~382,804~~a total of approximately 21.5 million shares of Class A Common Stock in connection with the IRM Acquisition, Tracker/Sequel Acquisitions and the Foreland Acquisition. No shares were issued in connection with acquisitions during 2020. During the years ended December 31, 2022, 2021 and 2020, as a result of the vesting and settlement of restricted stock units under the Earthstone Amended and Restated 2014 ~~Plan. During the period May 9, 2017 through December 31, 2017, the Company~~Long-Term Incentive Plan, as amended (the “2014 Plan”), Earthstone issued ~~320,410~~1,273,795, 1,381,825 and 914,905 shares of Class A Common Stock, ~~as a result of the vesting and settlement of restricted stock units under the 2014 Plan,~~respectively, of which ~~61,055~~429,547, 453,483 and 243,924 shares of Class A Common Stock, respectively, were ~~withheld by~~retained as treasury stock and cancelled to satisfy the ~~Company in exchange for payment of~~related employee income tax ~~withholdings. Additionally, on May 9, 2017, under the Bold Contribution Agreement,~~liability.

On October 11, 2022, Earthstone ~~issued 150,000~~purchased and immediately cancelled 3,000,000 shares of Class A Common Stock ~~valued at approximately $2.0 million on that date. For additional information, see~~ ~~Note 3. Acquisitions and Divestitures~~.

~~Class A Common Stock Offering~~

~~In October 2017, Earthstone completed~~from certain affiliates of Warburg Pincus LLC (“Warburg”) in a ~~public offering of 4,500,000 shares of Class A Common Stock, at~~private transaction, for an ~~issue~~aggregate purchase price of ~~$9.25~~$43,740,000, or $14.58 per share. Earthstone received net proceeds from this offering of $39.4 million, after deducting underwriters’ fees and offering expenses of $2.2 million. The net proceeds from the offering were used to repay outstanding indebtedness under the EEH Credit Agreement, as described in ~~Note 12. Long-Term Debt~~.

At December 31, ~~2017,~~2022 and 2021, there were ~~36,052,169~~34,259,641 and 34,344,532 shares of Class B Common Stock issued and ~~outstanding. On May 9, 2017, in connection with Earthstone’s completion of the Bold Transaction, Earthstone issued 36,070,828 shares of Class B Common Stock in exchange for $36 thousand.~~outstanding, respectively. Each share of Class B Common Stock, together with one EEH Unit, is convertible into one share of Class A Common Stock. ~~Earthstone did not have any Class B Common Stock issued at~~During the years ended December 31, ~~2016. For additional information, see~~ ~~Note 3. Acquisitions~~2022, 2021 and ~~Divestitures. Additionally, subsequent to the completion of the Bold Transaction, 18,659~~2020, 84,891, 664,839 and 251,309 shares, respectively, of Class B Common Stock and EEH Units were exchanged ~~along with 18,659 EEH Units,~~ for ~~18,659~~an equal number of shares of Class A Common Stock.

~~F-21~~

~~EARTHSTONE ENERGY, INC.~~

~~NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)~~

~~Common~~

The 2014 Plan allows, among other things, for the grant of restricted stock units (“RSUs”). ~~On May 9, 2017, and in connection with~~As of December 31, 2022, the ~~completion of the Bold Contribution Agreement, and upon approval by the stockholders of Earthstone, the 2014 Plan was amended to increase the~~maximum number of shares of Class A Common Stock ~~authorized to~~that may be issued under the 2014 Plan ~~by 4.3~~was 12.0 million ~~shares, to a total of 5.8 million~~ shares.

Each RSU represents the contingent right to receive one share of Class A Common Stock. The holders of outstanding RSUs do not receive dividends or have voting rights prior to vesting and ~~settlement. Prior to May 9, 2017, the~~settlement. The Company ~~determined the fair value of granted RSUs based on the market price of the Common Stock on the date of the grant. Beginning on May 9, 2017, the Company began determining~~determines the fair value of granted RSUs based on the market price of the Class A Common Stock on the date of the grant. Compensation expense for granted RSUs is recognized on a straight-line basis over the vesting term and is net of forfeitures, as incurred.

Stock-based compensation is included in General and administrative expense in the Consolidated Statements of Operations and is recorded with a corresponding increase in Additional paid-in capital within the Consolidated Balance Sheets.

The table below summarizes unvested RSU activity for the year ended December 31, ~~2017:~~

2022:

For the years ended December 31, ~~2017~~2022, 2021 and ~~2016~~2020, stock-based compensation related to RSUs was ~~$6.6~~$6.0 million, $5.2 million and ~~$3.3~~$5.4 million, respectively. ~~There was no stock-based compensation expense~~

The table below summarizes performance unit (“PSU”) activity for the year ended December 31, ~~2015. Stock-based~~2022:

The total grant date fair value of the PSUs granted during the years ended December 31, 2022, 2021 and 2020 were $9.2 million, $11.9 million and $5.6 million, respectively, with a weighted average grant date fair value per share of $19.42, $10.85 and $5.36, respectively. The total vesting date fair value of the PSUs that vested during 2022 and 2021 was $8.3 million and $3.5 million respectively. No PSUs vested during 2020. As of December 31, 2022, there was $16.1 million of unrecognized compensation expense ~~is recorded~~related to the PSU awards which will be amortized over a weighted average period of 0.71 years.

For the years ended December 31, 2022, 2021 and 2020, stock-based compensation related to the PSUs was approximately $29.4 million, $15.8 million and $4.6 million, respectively.

The Company classifies awards that will be settled in cash as liability awards. PSU grants to be settled in shares are classified as equity awards. Corresponding liabilities of $14.4 million and $7.8 million related to the PSUs were included in Other current liabilities and Accrued expenses, respectively, in the Consolidated ~~Statements~~Balance Sheets as of ~~Operations with a~~December 31, 2022 and 2021, respectively. Additionally, corresponding ~~increase~~liabilities of $10.4 million and $6.3 million related to the PSUs were included in ~~Additional paid-in capital within~~Other noncurrent liabilities in the Consolidated Balance ~~Sheet.~~

Sheets as of December 31, 2022 and 2021, respectively.

On February 1, 2022, the Board granted 472,485 PSUs (the “2022 PSUs”) to certain officers pursuant to the 2014 Plan. The 2022 PSUs are payable in cash or shares of Class A Common Stock upon the achievement by Earthstone over a period commencing on January 1, 2022 and ending on December 31, 2024 (the “2022 Performance Period”) of certain performance criteria established by the Board. The Company classifies these awards that will be settled in cash as liability awards. PSU grants to be settled in shares are classified as equity awards.

The 2022 PSUs are eligible to be earned based on the annualized Total Shareholder Return (“TSR”) of the Class A Common Stock during a three-year period beginning on January 1, 2022. Between 0x to 2.0x of the Performance Units are eligible to be earned based on Earthstone achieving an annualized TSR based on the following pre-established goals:

In the event that greater than 1.0x of the 2022 PSUs are earned, such additional PSUs may be paid in cash rather than the issuance of shares of Class A Common Stock.

On January 27, 2021, the Board granted 1,099,800 PSUs (the “2021 PSUs”) to certain officers pursuant to the 2014 Plan (the “2021 Grant”). The 2021 PSUs are payable in cash or shares of Class A Common Stock upon the achievement by the Company over a period commencing on January 1, 2021 and ending on December 31, 2023 of certain performance criteria established by the Board. The Company classifies these awards that will be settled in cash as liability awards. PSU grants to be settled in shares are classified as equity awards.

The 2021 PSUs are eligible to be earned based on the annualized TSR of the Class A Common Stock during a three-year period beginning on February 1, 2021. Between 0x to 2.0x of the Performance Units are eligible to be earned based on Earthstone achieving an annualized TSR based on the following pre-established goals:

In the event that greater than 1.0x of the 2021 PSUs are earned, such additional PSUs may be paid in cash rather than the issuance of shares of Class A Common Stock.

The Company accounts for these awards as market-based awards which are valued quarterly utilizing the Monte Carlo Simulation pricing model, which calculates multiple potential outcomes for an award and establishes grant date fair value based on the most likely outcome. For the 2021 PSUs, assuming a risk-free rate of 0.3% and volatility of 86.0%, the Company calculated the weighted average grant date fair value per PSU to be $10.85.

On January 30, 2020, the Board granted 1,043,800 PSUs (the “2020 PSUs”) to certain officers pursuant to the 2014 Plan (the “2020 Grant”). The 2020 PSUs are payable in shares of Class A Common Stock based upon the achievement by the Company over a period commencing on February 1, 2020 and ending on January 31, 2023 of certain performance criteria established by the Board.

The 2020 PSUs are eligible to be earned based on the annualized TSR of the Class A Common Stock during a three-year period beginning on February 1, 2020. Between 0x to 2.0x of the Performance Units are eligible to be earned based on Earthstone achieving an annualized TSR based on the following pre-established goals:

In the event that greater than 1.0x of the 2020 PSUs are earned, such additional PSUs may be paid in cash rather than the issuance of shares of Class A Common Stock, solely at the discretion of the Board.

The Company accounts for these awards as market-based awards which are valued utilizing the Monte Carlo Simulation pricing model, which calculates multiple potential outcomes for an award and establishes grant date fair value based on the most likely outcome. For the 2020 PSUs, assuming a risk-free rate of 1.4% and volatility of 62.0%, the Company calculated the weighted average grant date fair value per PSU to be $5.36.

On January 28, 2019, the Board granted 669,550 PSUs (the “2019 PSUs”) to certain executive officers pursuant to the 2014 Plan. The PSUs are payable in shares of Class A Common Stock based upon the achievement by the Company over a period commencing on February 1, 2019 and ending on January 31, 2022 of performance criteria established by the Board.

The number of shares of Class A Common Stock that may be issued will be determined by multiplying the number of PSUs granted by the Relative TSR Percentage (0% to 200%). The “Relative TSR Percentage” is the percentage, if any, achieved by attainment of a certain predetermined range of targets for the three-year period beginning on February 1, 2019.

The Company accounts for these awards as market-based awards which are valued utilizing the Monte Carlo Simulation pricing model, which calculates multiple potential outcomes for an award and establishes grant date fair value based on the most likely outcome. For the PSUs granted on January 28, 2019, assuming a risk-free rate of 2.6% and volatilities ranging from 40.1% to 114.1%, the Company calculated the weighted average grant date fair value per PSU to be $9.30.

The 2019 PSUs were settled on February 9, 2022 resulting in the issuance of 608,125 shares of Class A Common Stock and cash payments totaling $8.1 million.

All outstanding PSUs may be paid in either cash or the issuance of shares of Class A Common Stock or any combination of the two therein, at the discretion of the Board. In January 2023, the Board, at its discretion, consented to settlement of the 2020 Grant in shares of Class A Common Stock up to 100% and the remaining 100% in cash. In consideration of the settlement of the 2020 Grant, which was consistent with the 2019 Grant, the Company deemed it appropriate to modify the remaining performance-based grants (the “Modification”). Based on the Modification, the Company calculated the fair value of the cash settled portion of each award representing an estimated accumulative increase to the liability of $9.9 million as of December 31, 2022, consisting of $17.1 million in additional stock-based compensation during the year ended December 31, 2022, partially offset by $7.2 million of stock-based compensation previously recognized in Additional Paid-in Capital.

During the years ended December 31, 2022 and 2021, the Company recorded gross expense related to stock-based compensation of approximately $35.4 million (net of $4.1 million of income tax benefit) and $21.0 million (net of $2.8 million of income tax benefit), respectively.

The ~~EEH~~ Credit Agreement contains customary affirmative covenants and defines events of default to include failure to pay principal or interest, breach of covenants, breach of representations and warranties, insolvency, judgment default and ~~if Frank A. Lodzinski ceases to serve and function as Chief Executive Officer of EEH and the majority of the Lenders do not approve of Mr. Lodzinski’s successor.~~a change in control. Upon the occurrence and continuance of an event of default, the Lenders have the right to accelerate repayment of the loans and exercise their remedies with respect to the collateral. As of December 31, ~~2017,~~2022, EEH was in compliance with ~~all~~the covenants under the ~~EEH~~ Credit Agreement.

December 31,

2017

2016

Credit Agreement

$
25,000

$
10,000

Promissory note

—

4,297

Total debt

25,000

14,297

Less: Current portion of long-term debt

—

(1,604
)
Long-term debt

$
25,000

$
12,693

For the ~~years~~year ended December 31, ~~2017, 2016 and 2015,~~2022, interest on ~~all outstanding debt~~the revolving tranche of the Credit Agreement averaged ~~4.26%, 4.03% and 1.68%~~4.74% per annum, ~~respectively, of~~ which excluded commitment fees of ~~$0.3~~$1.7 million ~~for each period ended~~ and amortization of deferred financing costs of $3.2 million. For the year

ended December 31, 2022, interest on the term loan tranche of the Credit Agreement averaged 6.67% per annum, which excluded amortization of deferred financing costs of $0.5 million. For the years ended December 31, 2021 and 2020, interest on borrowings under the Credit Agreement averaged 3.40% and 2.83% per annum, respectively, which excluded commitment fees of $0.9 million and $0.6 million for each period ended, respectively, and amortization of deferred financing costs of $0.9 million and $0.3 million for each period ended, respectively.

~~The~~

During the year ended December 31, 2022, the Company capitalized ~~$1.4 million, $0.1~~$6.5 million and ~~$0.1~~$5.8 million ~~respectively,~~ of costs associated with the ~~credit agreements~~revolving tranche and term loan tranche of the Credit Agreement, respectively. The Company capitalized $2.8 million costs associated with the Credit Agreement for the ~~years~~year ended December 31, ~~2017, 2016 and 2015. These~~2021. No costs associated with the Credit Agreement were capitalized ~~costs are included in Other noncurrent assets in~~during the ~~Consolidated Balance Sheets.~~year ended December 31, 2020. The Company’s policy is to capitalize the financing costs associated with its debt and amortize those costs on a straight-line basis over the term of the associated debt, which approximates the effective interest method over the term of the related debt.

As of December 31, 2022, accrued interest of $9.5 million associated with the Notes was included in Accrued expenses in the Consolidated Balance Sheets.

The Company has asset retirement obligations associated with the future plugging and abandonment of oil and natural gas properties and related facilities. Revisions to the liability typically occur due to changes in the estimated abandonment costs, well economic lives, and the discount rate.

Additionally, the Company leases corporate office space in The Woodlands, ~~Texas,~~Texas; Midland, Texas and ~~Denver, Colorado.~~ San Angelo, Texas. Rent expense was approximately $0.9 million, $0.8 million and $0.8 million, for the years ended December 31, ~~2017, 2016,~~2022, 2021 and ~~2015,~~2020, respectively. Minimum lease payments under the terms of ~~non-cancelable~~non-cancellable operating leases as of December 31, ~~2017~~2022 are ~~shown~~included in the table above.

The Company’s operations are subject to risks normally associated with the drilling, completion and production of oil and gas, including blowouts, fires, and environmental risks such as oil spills or gas leaks that could expose the Company to liabilities associated with these risks.

In the Company’s acquisition of existing or previously drilled well bores, the Company 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. The Company maintains comprehensive insurance coverage that it believes 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 fall upon the Company. No claim has been made, nor is the Company aware of any liability which the Company may have, as it relates to any environmental cleanup, restoration, or the violation of any rules or regulations relating thereto except for the matter discussed above.

Years Ended December 31,

2017

2016

2015

Current:

Federal

$
—

$
—

$
—

State

(15
)

—

(91
)
Total current

(15
)

—

(91
)

Deferred:

Federal

16,186

(515
)

26,214

State

202

(13
)

319

Total deferred

16,388

(528
)

26,533

Total income tax benefit (provision)

$
16,373

$
(528
)

$
26,442

During the year ended December 31, ~~2017,~~2022, the Company recorded total income tax expense of $124.4 million which included (1) deferred income tax expense for Lynden US of $7.1 million as a result of its share of the distributable income from EEH, (2)

deferred income tax expense for Earthstone of $107.8 million, which included a deferred income tax expense of $114.9 million, resulting from its share of the distributable income from EEH, offset by a $7.1 million release of valuation allowance, (3) current income tax expense of $1.8 million solely related to the Texas Margin Tax and (4) state deferred income tax expense of $0.8 million related to the Texas Margin Tax and $6.9 million related to New Mexico corporate income tax expense. Lynden Corp incurred no material income or loss, or related income tax expense or benefit, for the year ended December 31, 2022.

During the year ended December 31, 2021, the Company recorded total income tax expense of $1.9 million which included (1) deferred income tax expense for Lynden US of $0.9 million as a result of its share of the distributable income from EEH, (2) deferred income tax expense for Earthstone of $6.3 million as a result of its share of the distributable income 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 $0.63 million, offset by deferred income tax expense of $0.33 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, 2021.

During the year ended December 31, 2020, the Company recorded total income tax benefit of ~~$16.4~~$0.11 million which ~~was primarily driven by the change in valuation allowance associated with the Bold Transaction. For Lynden US, the Company recorded an~~included (1) deferred income tax benefit for Lynden US of ~~$8.6~~$0.15 million as a result of ~~which $4.8 million related to~~its share of the ~~reduction of that amount in its~~distributable income from EEH, (2) deferred ~~tax liability resulting from the federal corporate income tax rate reduction to 21% as described below. Additionally, the Company recorded an~~ income tax benefit for Earthstone of ~~$7.7~~$0.61 million ~~which resulted from~~as a ~~change in assessment~~result of its share of the ~~realization of~~distributable income from EEH, which was used to reduce the valuation allowance recorded against its ~~net~~ deferred tax assets due to the deferred tax liability that was recorded with respect to its investment in EEH as part of the Bold Transaction as an adjustment to Additional paid-in capital within the Consolidated Balance Sheet. Additionally, Earthstone recordedasset cannot be assured and (3) current income tax expense of ~~$12.6~~$0.55 million, offset by deferred income tax benefit of $0.51 million related to the ~~reduction of that amount in its deferred tax asset resulting from the federal corporate~~Texas Margin Tax. Lynden Corp incurred no material income or loss, or related income tax rate reduction to 21% as described below, which was fully offset by the reduction in its valuation allowance for that amount because the future realization of such loss cannot be reasonably assured and is subject to a full valuation allowance.

~~On December 22, 2017, the United States enacted tax reform legislation commonly known as the TCJA, resulting in significant modifications to existing law. Our consolidated financial statements~~expense or benefit, for the year ended December 31, ~~2017, reflect certain effects of the TCJA, which includes~~ ~~the federal corporate income tax rate reduction~~ to 21%. Consistent with Staff Accounting Bulletin No. 118 issued by the SEC, which provides for a measurement period of one year from the enactment date to finalize the accounting for effects of the TCJA, the Company provisionally recorded income tax expense of $7.8 million related to the TCJA. In accordance with SEC guidance, provisional amounts may be refined as a result of additional guidance from, and interpretations by, U.S. regulatory and standard-setting bodies, and changes in assumptions. In the subsequent period, provisional amounts will be adjusted for the effects, if any, of interpretative guidance issued after December 31, 2017, by the U.S. Department of the Treasury. The effects of the TCJA may be subject to changes for items that were previously reported as provisional amounts, as well as any element of the TCJA for which a provisional estimate could not be made, and such changes could be material.

The Company has made provisional computations of the impact of the TCJA as provided for under SAB 118, including transition tax on the mandatory deemed repatriation of foreign earnings and executive compensation limitations under Internal Revenue Code Section 162(m), among others. The Internal Revenue Service is expected to issue additional guidance clarifying provisions of the Act. As additional guidance is issued one or more of the provisional amounts may change.

The Company’s effective tax rate for the year ended December 31, 2016, was approximately (1.0)% which was less than the U.S. Federal statutory tax rate primarily due to both the recording of a $12.2 million valuation allowance as the realizability of the Company’s deferred tax assets is not more likely-than-not, and $6.0 million reduction of income tax benefit resulting from non-deductible impairment of goodwill.

~~F-27~~

~~EARTHSTONE ENERGY, INC.~~

~~NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)~~

~~A reconciliation of the effective tax rate to the statutory rate for the year ended December 31, 2015 is as follows (in thousands, except percentages~~):

2020.

As of December 31, ~~2016,~~2021, the Company had a valuation allowance recorded against its deferred tax assets of ~~$39.6~~$10.8 million which is in excess of its Net deferred noncurrent tax assets of ~~$23.8~~$7.8 million, as presented above. The Company’s corporate organizational structure requires the filing of two separate consolidated U.S. Federal income tax returns, one separate U.S. Federal partnership income tax return and one Canadian income tax return. As a result, tax attributes of one group cannot be offset by the tax attributes of another. At December 31, ~~2016,~~2021, the deferred tax assets and liabilities related to the two U.S. Federal income tax returns, ~~and~~ one Canadian income tax ~~return are~~and one related to the Texas Margin Tax were a ~~$36.0~~$19.7 million deferred tax asset, a ~~$15.8~~$10.4 million deferred tax liability, ~~and~~ a ~~$3.6~~$3.8 million deferred tax asset ~~respectively.~~

~~F-28~~

~~EARTHSTONE ENERGY, INC.~~

~~NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)~~

and a $5.3 million deferred tax liability, respectively, before considering the valuation allowance of $10.8 million.

As of December 31, ~~2017, the Company~~2022, (1) Earthstone had estimated U.S. net operating loss carryforwards of ~~$49.1~~$29.1 million, ~~the first~~ expiring in ~~2034~~2036 and ~~the last in~~ 2037 and $120.1 million with an indefinite carryforward life (“ICL”), (2) Lynden US had estimated U.S. net operating loss carryforwards available for use of $3.7 million, expiring from 2036 through 2037 and $22.4 million with an indefinite

Additionally, the ability to utilize net operating losses and other tax attributes could be subject to a significant limitation if the Company were to undergo an ownership change for the purposes of Section 382 (“Sec 382”) of the Internal Revenue Code of 1986, as amended (the “Code”). ~~The~~On February 15, 2022, the Company ~~has~~completed the Chisholm Acquisition which included the issuance of 19,417,476 shares of Class A Common Stock, which resulted in an ~~additional estimated U.S.~~ownership change within the meaning of Sec 382. As a result of the ownership change, the Company’s annual usage of net operating ~~loss~~losses (“NOLs”) and credits generated prior to the ownership change date may be limited, however, at this time, we do not expect any of the losses to expire unused as a result of this ownership change. Earthstone generated approximately $97.6 million in NOL carryforward assets in 2022, of ~~$28.0~~which, $85.3 million ~~limited by Sec~~relates to the time period post ownership change within the meaning of Section 382 ~~resulting from~~and is not subject to limitation. Lynden US generated approximately $14.3 million in NOL carryforward assets in 2022, of which, $12.5 million relates to the time period post ownership change within the meaning of Section 382 and is not subject to limitation. Lynden ~~Arrangement.~~US previously experienced an ownership change on May 17, 2016 and at that time certain NOLs were identified as being expected to expire unusable. The Company continues to evaluate the impact, if any, of potential Sec 382 limitations.

The Company files two ~~federal~~Federal income tax returns, one Canadian income tax return and various combined and separate filings in several state and local jurisdictions. The Company’s practice is to recognize estimated interest and penalties, if any, related to potential underpayment of income taxes as a component of income tax expense in its Consolidated Statement of Operations. As of December 31, ~~2017,~~2022, the Company did not have any accrued interest or penalties associated with any uncertain tax liabilities.

The Company sponsors a 401(k) defined contribution plan (the “401(k) Plan”) for substantially all of its employees, which was initiated in April 2017. Eligible employees may make contributions to the 401(k) Plan by electing to contribute up to 100% of their annual compensation, not to exceed annual limits established by the federal government. The Company makes matching contributions of up100% of employee contributions, not to exceed six percent of the ~~eligible~~ employee’s annual ~~compensation contributed.~~eligible compensation. The Company’s matching contributions vest immediately. The Company’s contributions to the 401(k) Plan for the ~~year~~years ended December 31, ~~2017~~2022, 2021 and 2020 were ~~$0.3 million.~~

$1.1 million, $0.5 million and $0.5 million, respectively.

The following table shows the weighted average remaining lease term and ~~natural gas properties,~~the weighted average discount rate for the Company’s leases as ~~discussed~~of the dates indicated:

Capitalized costs include the cost of properties, equipment, and facilities for oil and natural gas producing activities. Capitalized costs for proved properties include costs for oil and natural gas leaseholds where proved reserves have been identified, development wells, and related equipment and facilities, including development wells in progress. Capitalized costs for unproved properties include costs for acquiring oil and natural gas leaseholds where no proved reserves have been identified, including costs of exploratory wells that are in the process of drilling or in active completion, and costs of exploratory wells suspended or waiting on completion.

⁽¹⁾

~~Acquisition costs incurred during 2017 consisted primarily of the assets acquired in the Bold Transaction described in~~ ~~Note 3. Acquisitions and Divestitures~~ ~~of the Notes to Consolidated Financial Statements.~~

During the years ended December 31, ~~2016~~2022, 2021 and ~~2015, additions to oil and natural gas properties of $0.2 million were recorded for estimated costs of future abandonment related to new wells drilled or acquired.~~

~~For the years ended December 31, 2017, 2016 and 2015,~~2020, the Company had no capitalized exploratory well costs, nor capitalized costs related to share-based compensation, general corporate overhead or similar activities.


Title of each class	Trading Symbol	Name of each exchange on which registered
Class A Common Stock, $0.001 par value per share	ESTE	~~NYSE~~ New York Stock Exchange (NYSE)

	~~Page~~
		Page
Glossary of Certain Oil and Natural Gas Terms			5 6

PART I
Item 1.	Business		8 9
Item 1A.	Risk Factors		22 28
Item 1B.	Unresolved Staff Comments		37 46
Item 2.	Properties		37 47
Item 3.	Legal Proceedings		47 55
Item 4.	Mine Safety Disclosures		47 55
PART II
Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities		48 56
Item 6.	~~Selected Financial Data~~Reserved		50 57
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations		51 57
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk		65 68
Item 8.	Financial Statements and Supplemental Data		66 69
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure		66 69
Item 9A.	Controls and Procedures		66 69
Item 9B.	Other Information		69 73
Item 9C.	Disclosure Regarding Foreign Jurisdictions that Prevent Inspections	73
PART III
Item 10.	Directors, Executive Officers and Corporate Governance		69 73
Item 11.	Executive Compensation		69 73
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters		69 73
Item 13.	Certain Relationships and Related Transactions, and Director Independence		69 73
Item 14.	Principal ~~Accounting~~Accountant Fees and Services		69 73
PART IV
Item 15.	~~Exhibits,~~Exhibit and Financial Statements ~~and~~ Schedules		70 74
Item 16.	Form 10-K Summary		74 80
Signatures			75 81

	Oil			Natural Gas			NGLs			Total
	(MBbl)			(MMcf)			(MBbl)			(MBOE)
Balance - December 31, 2014		13,803			38,579			1,959			22,192
Extensions and discoveries		526			828			21			685
Sales of minerals in place		(4	)		(8,040	)		—			(1,344	)
Purchases of minerals in place		1,641			679			208			1,962
Production		(904	)		(2,143	)		(176	)		(1,437	)
Revision to previous estimates		(5,701	)		(16,565	)		(1,022	)		(9,484	)

Balance - December 31, 2015		9,361			13,338			990			12,574
Extensions and discoveries		345			285			30			423
Purchases of minerals in place		5,548			14,770			2,637			10,647
Production		(878	)		(2,171	)		(225	)		(1,465	)
Revision to previous estimates		(7,265	)		(5,821	)		(1,892	)		(10,128	)

Balance - December 31, 2016		7,111			20,401			1,540			12,051
Extensions and discoveries		19,558			29,644			6,264			30,763
Sales of minerals in place		(1,833	)		(6,853	)		(1	)		(2,976	)
Purchases of minerals in place		28,176			46,709			9,950			45,911
Production		(1,828	)		(3,260	)		(500	)		(2,872	)
Revision to previous estimates		(3,857	)		4,447			215			(2,901	)
Balance - December 31, 2017 ⁽¹⁾		47,327			91,088			17,468			79,976

Proved developed reserves:
December 31, 2014		6,093			16,214			1,005			9,800
December 31, 2015		6,114			10,954			673			8,613
December 31, 2016		6,052			13,545			1,051			9,361
December 31, 2017 ⁽²⁾		11,949			23,336			4,123			19,961

Proved undeveloped reserves:
December 31, 2014		7,710			22,365			954			12,392
December 31, 2015		3,247			2,384			317			3,961
December 31, 2016		1,059			6,856			489			2,690
December 31, 2017 ⁽³⁾		35,378			67,752			13,345			60,015


	Oil (MBbl)	Natural Gas (MMcf)	Natural Gas Liquids (MBbl)	Total (MBoe)
Balance - December 31, 2021	61,075	284,881	39,031	147,587
Extensions	13,430	51,346	7,895	29,883
Sales of minerals in place	(2,044)	(6,631)	(1,417)	(4,566)
Purchases of minerals in place	85,237	429,646	56,268	213,113
Production	(11,866)	(54,392)	(7,599)	(28,531)
Revision to previous estimates	(7,432)	37,316	11,663	10,450
Balance - December 31, 2022	138,400	742,166	105,841	367,936

Proved developed reserves:	88,759	574,762	80,168	264,721

Proved undeveloped reserves:	49,641	167,404	25,673	103,215


	Oil (MBbl)	Natural Gas (MMcf)	Natural Gas Liquids (MBbl)	Total (MBoe)
Proved developed	21,750	140,845	19,645	64,870
Proved undeveloped	12,165	41,022	6,291	25,293
Total proved	33,915	181,867	25,936	90,163

☑
☑			ANNUAL REPORT ~~UNDER~~PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

☐
☐			TRANSITION REPORT ~~UNDER~~PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

	Oil		Natural Gas		NGL		Total		% of Total			Undiscounted Future Net Cash Flows		PV-10		Standardized Measure of Discounted Future Net Cash Flows		Future Capital Expenditures
	(MBbl)		(MMcf)		(MBbl)		(MBOE) ⁽²⁾		Proved			($ In thousands)		($ In thousands)		($ In thousands)		($ In thousands)
PDP		10,854		21,387		3,754		18,172		23	%	$	414,383	$	253,156	$	250,644	$	—
PDNP		1,095		1,949		369		1,789		2	%		36,224		20,637		20,432		11,177
PUD		35,378		67,752		13,345		60,015		75	%		1,023,000		324,848		321,624		665,916
Total proved ⁽¹⁾		47,327		91,088		17,468		79,976		100	%	$	1,473,607	$	598,641	$	592,700	$	677,093


Proved undeveloped reserves at December 31, ~~2014~~ 2021 (1)		54,012		~~12,392~~
Conversions to developed		(22,637)		~~(1,700~~	)
Extensions ~~and discoveries~~		16,499		~~685~~

Purchases of minerals in place		57,432		~~1,924~~
Revision to previous estimates		(2,091)		~~(9,340~~	)

Proved undeveloped reserves at December 31, ~~2015~~ 2022 (2)	103,215		~~3,961~~
~~Conversions to developed~~		~~(169~~	)
~~Extensions and discoveries~~		~~293~~
~~Purchases of minerals in place~~		~~873~~
~~Revision to previous estimates~~		~~(2,268~~	)

~~Proved undeveloped reserves at December 31, 2016~~		~~2,690~~
~~Conversions to developed~~		~~(2,756~~	)
~~Extensions and discoveries~~		~~27,977~~
~~Sales of minerals in place~~		~~(391~~	)
~~Purchases of minerals in place~~		~~37,327~~
~~Revision to previous estimates~~		~~(4,832~~	)
~~Proved undeveloped reserves at December 31, 2017~~ ⁽¹⁾		~~60,015~~

Years Ended December 31, ⁽¹⁾	Future Production (MBOE) ⁽²⁾		Future Cash Inflows ⁽³⁾		Future Production Costs		Future Development Costs		Future Net Cash Flows
2018		400	$	15,911	$	2,079	$	51,949	$	(38,117	)
2019		2,283		89,608		11,751		114,947		(37,090	)
2020		5,264		209,703		27,346		243,816		(61,459	)
2021		7,565		289,293		39,170		212,498		37,625
2022		6,209		223,884		33,806		42,706		147,372
Thereafter		38,294		1,377,897		403,228		—		974,669
Total		60,015	$	2,206,296	$	517,380	$	665,916	$	1,023,000


Years Ended December 31, (1)	Future Production (MBoe) (2)	Future Cash Inflows (3)		Future Production Costs		Future Development Costs		Future Net Cash Flows
2023	5,566	$	421,503	$	57,973	$	454,756	$	(91,227)
2024	10,878	814,602		118,413		447,281		248,908
2025	12,733	924,063		140,342		286,318		497,403
2026	9,962	673,699		112,375		12,242		549,083
2027	7,082	454,295		81,801		—		372,495
Thereafter	56,994	3,400,497		1,023,473		—		2,377,024
Total	103,215	$	6,688,659	$	1,534,377	$	1,200,597	$	3,953,686

	Oil				Natural Gas				Total
	Gross Wells		Net Wells		Gross Wells		Net Wells		Gross Wells		Net Wells
Midland Basin		193		94		2		1		195		95
Eagle Ford Trend		109		46		56		6		165		52
Other ⁽¹⁾		1		1		-		-		1		1

	Developed				Undeveloped ⁽¹⁾				Total
State	Gross		Net		Gross		Net		Gross		Net
Texas		77,098		39,532		23,588		6,989		100,686		46,521
Other		960		770		6,979		3,141		7,939		3,911
Total		78,058		40,302		30,567		10,130		108,625		50,432

	Net Exploratory Wells Drilled				Net Development Wells Drilled				Total Net Productive and Dry Wells
Year	Productive		Dry		Productive		Dry		Drilled
2017		—		—		11.0		—		11.0
2016		—		—		7.7		—		7.7
2015		—		—		7.2		—		7.2

	Class A Common Stock Price
Period	High		Low
2017
First Quarter	$	15.50	$	11.26
Second Quarter	$	15.00	$	9.07
Third Quarter	$	11.68	$	8.49
Fourth Quarter	$	11.13	$	7.85

2016
First Quarter	$	14.19	$	10.75
Second Quarter	$	15.93	$	10.12
Third Quarter	$	11.66	$	7.67
Fourth Quarter	$	15.71	$	8.02

	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 2017		—		—		—		—
November 2017		—		—		—		—
December 2017		31,614	$	10.63		—		—

	12/31/2012		12/31/2013		12/31/2014		12/31/2015		12/31/2016		12/31/2017
Earthstone Energy, Inc.	$	100.00	$	119.43	$	151.71	$	85.93	$	88.70	$	68.62
S&P 500 Index	$	100.00	$	132.39	$	150.51	$	152.59	$	170.84	$	208.14
S&P 500 Oil & Gas Exploration & Production Index	$	100.00	$	127.09	$	88.85	$	56.23	$	77.09	$	69.33


Period	Commodity	Volume (Bbls / MMBtu)	Price ($/Bbl / $/MMBtu)
2023	Crude Oil Swap	1,642,500	$76.94
2023	Crude Oil Basis Swap(1)	9,488,500	$0.92
2023	Natural Gas Swap	3,670,000	$3.52
2023	Natural Gas Basis Swap(2)	51,100,000	$(1.67)
2024	Natural Gas Basis Swap(2)	36,600,000	$(1.05)


	Costless Collars
Period	Commodity	Volume (Bbls / MMBtu)	Bought Floor ($/Bbl / $/MMBtu)		Sold Ceiling ($/Bbl / $/MMBtu)
2023	Crude Oil Costless Collar	2,080,500	$	63.33	$	82.83

2023	Natural Gas Costless Collar	22,188,000	$	3.82	$	7.44


	Deferred Premium Puts
Period	Commodity	Volume (Bbls / MMBtu)	$/Bbl (Put Price)		$/Bbl (Net of Premium)
2023	Crude Oil	1,931,500	$	69.53	$	64.12


		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
2.3	Purchase and Sale Agreement dated March 31, 2021, among Tracker Resource Development III, LLC, TRD III Royalty Holdings (TX), LP, Earthstone Energy, Inc. and Earthstone Energy Holdings, LLC.	8-K	001-35049	2.1	April 5, 2021
2.4	Purchase and Sale Agreement dated March 31, 2021, among SEG-TRD LLC, SEG-TRD II LLC, Earthstone Energy, Inc. and Earthstone Energy Holdings, LLC.	8-K	001-35049	2.2	April 5, 2021
2.5	Purchase and Sale Agreement dated as of September 30, 2021, by and among Earthstone Energy, Inc., Earthstone Energy Holdings, LLC, and Foreland Investments LP.	8-K	001-35049	2.1	October 4, 2021
2.6	Purchase and Sale Agreement dated as of September 30, 2021, by and among Earthstone Energy, Inc., Earthstone Energy Holdings, LLC, and BCC-Foreland LLC.	8-K	001-35049	2.2	October 4, 2021
2.7	Purchase and Sale Agreement dated December 15, 2021, by and between Chisholm Energy Operating, LLC, Chisholm Energy Agent, Inc., Earthstone Energy, Inc., and Earthstone Energy Holdings, LLC.	8-K	001-35049	2.1	December 17, 2021
2.8	Purchase and Sale Agreement dated January 30, 2022, by and among Bighorn Asset Company, LLC, Earthstone Energy, Inc. and Earthstone Energy Holdings, LLC.	8-K	001-35049	2.1	February 2, 2022
2.9	Purchase and Sale Agreement dated June 27, 2022, by and among Titus Oil & Gas Production, LLC, Titus Oil & Gas Corporation, Lenox Minerals, LLC and Lenox Mineral Title Holdings, Inc, collectively, as Seller, and Earthstone Energy Holdings, LLC, as purchaser, and Earthstone Energy, Inc.	8-K	001-35049	2.1	June 29, 2022


2.10	Purchase and Sale Agreement dated June 27, 2022, by and among Titus Oil & Gas Production II, LLC, Lenox Minerals II, LLC and Lenox Mineral Holdings II, LLC, collectively, as Seller and Earthstone Energy Holdings, LLC, as Purchaser and Earthstone Energy, Inc.	8-K	001-35049	2.2	June 29, 2022
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
3.1(a)	Certificate of Amendment to the Third Amended and Restated Certificate of Incorporation of Earthstone Energy, Inc. dated July 20, 2021.	8-K	001-35049	3.1	July 23, 2021
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
3.3	Certificate of Designation, Preferences, Rights and Limitations of the Series A Convertible Preferred Stock.	8-K	001-35049	3.1	April 18, 2022
3.4	Certificate of Elimination of Series A Convertible Preferred Stock.	8-K	001-35049	3.1	July 15, 2022
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
4.3	Indenture, dated as of April 12, 2022, by and among Earthstone Energy Holdings, LLC, Earthstone Energy, Inc., Earthstone Operating, LLC, Earthstone Permian LLC, Sabine River Energy, LLC, Independence Resources Technologies, LLC, and U.S. Bank Trust Company, National Association, as Trustee.	8-K	001-35049	4.1	April 13, 2022
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
10.5	Second Amended and Restated Limited Liability Company Agreement of Earthstone Energy Holdings, LLC dated April 18, 2022.	8-K	001-35049	10.6	April 18, 2022
10.6	Registration Rights Agreement dated May 9, 2017 between Earthstone Energy, Inc. and Bold Energy Holdings, LLC.	8-K	001-35049	10.3	April 18, 2022
10.9†	Amended and Restated 2014 Long Term Incentive Plan dated June 6, 2018.	8-K	001-35049	10.1	June 6, 2018


10.12(f)	Amended and Restated Fifth Amendment to Credit Agreement dated as of January 30, 2022, among Earthstone Energy Holdings, LLC, as Borrower, Earthstone Energy, Inc., as Parent, Wells Fargo Bank, National Association, as Administrative Agent, the lenders and guarantors party thereto.	8-K	001-35049	10.1	February 2, 2022
10.12(g)	Sixth Amendment to Credit Agreement dated as of June 2, 2022, by and among Earthstone Energy Holdings, LLC, as Borrower, Earthstone Energy, Inc., as Parent, Wells Fargo Bank, National Association as Administrative Agent, and the Lenders and guarantors party thereto.	8-K	001-35049	10.1	June 2, 2022
10.12(h)	Seventh Amendment to Credit Agreement dated as of August 10, 2022, by and among Earthstone Energy Holdings, LLC, as Borrower, Earthstone Energy, Inc., as Parent, Wells Fargo Bank, National Association as Administrative Agent, and the Lenders and guarantors party thereto.	8-K	001-35049	10.3	August 11, 2022
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
10.19†	Form of Performance Unit Agreement (Executive Management).	8-K	001-35049	10.1	January 29, 2021
10.21	Registration Rights Agreement dated July 20, 2021, by and among Earthstone Energy, Inc., Tracker Resource Development III, LLC, EnCap Energy Capital Fund VIII, L.P., ZIP Ventures I, L.L.C, and Tracker III Holdings, LLC.	8-K	001-35049	10.1	July 23, 2021
10.22	Registration Rights Agreement dated July 20, 2021, by and among Earthstone Energy, Inc., SEG-TRD LLC, and SEG-TRD II LLC.	8-K	001-35049	10.2	July 23, 2021
10.25	Registration Rights Agreement dated November 2, 2021, by and among Earthstone Energy, Inc., Foreland Investments LP, the parties listed on Schedule I thereto, and the Persons identified on Schedule II thereto.	8-K	001-35049	10.1	November 2, 2021
10.26	Form of Lock-up Agreement.	8-K	001-35049	10.2	November 2, 2021
10.27	Securities Purchase Agreement dated as of January 30, 2022, by and among Earthstone Energy, Inc. and the purchasers set forth therein.	8-K	001-35049	10.2	February 2, 2022


10.28	Registration Rights Agreement dated February 15, 2022 by and among Earthstone Energy, Inc., Chisholm Energy Operating, LLC, and Chisholm Energy Holdings, LLC.	8-K	001-35049	10.1	February 18, 2022
10.29	Form of Lock-up Agreement.	8-K	001-35049	10.2	February 18, 2022
10.30	Amended and Restated Voting Agreement dated February 15, 2022, 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., WP Energy Chisholm Holdings, L.P., WP Energy Partners Chisholm Holdings, L.P., Warburg Pincus Energy (E&P) Partners-B Chisholm, LLC, Warburg Pincus Private Equity (E&P) XII (A), L.P., WP XII Chisholm Holdings, L.P., Warburg Pincus XII (E&P) Partners-2 Chisholm, LLC, Warburg Pincus Private Equity (E&P) XII-D (A), L.P., Warburg Pincus Private Equity (E&P) XII-E (A), L.P., Warburg Pincus XII (E&P) Partners-1, L.P., and WP XII (E&P) Partners (A), L.P.	8-K	001-35049	10.3	February 18, 2022
10.30(a)	First Amendment to Amended and Restated Voting Agreement dated August 1, 2022, 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, L.P., Warburg Pincus Energy (E&P) Partners-A, L.P., Warburg Pincus Energy (E&P) Partners-B IRH, LLC, WP Energy Partners IRH Holdings, L.P., WP Energy IRH Holdings, L.P., WP Energy Chisholm Holdings, L.P., WP Energy Partners Chisholm Holdings, L.P., Warburg Pincus Energy (E&P) Partners-B Chisholm, LLC, Warburg Pincus Private Equity (E&P) XII (A), L.P., WP XII Chisholm Holdings, L.P., Warburg Pincus XII (E&P) Partners-2 Chisholm, LLC, Warburg Pincus Private Equity (E&P) XII-D (A), L.P., Warburg Pincus Private Equity (E&P) XII-E (A), L.P., Warburg Pincus XII (E&P) Partners-1, L.P., and WP XII (E&P) Partners (A), L.P., and EnCap Investments L.P.	8-K	001-35049	10.1	August 1, 2022


10.31	Purchase Agreement dated as of April 7, 2022, by and among Earthstone Energy Holdings, LLC, Earthstone Energy, Inc., Earthstone Operating, LLC, Earthstone Permian LLC, Sabine River Energy, LLC, Independence Resources Technologies, LLC, and RBC Capital Markets, LLC, as representative of the initial purchasers named therein.	8-K	001-35049	10.1	April 13, 2022
10.32	Registration Rights Agreement dated April 14, 2022, by and among Earthstone Energy, Inc. and Bighorn Permian Resources, LLC.	8-K	001-35049	10.2	April 18, 2022
10.33	Registration Rights Agreement dated April 14, 2022, by and among Earthstone Energy, Inc., EnCap Energy Capital Fund XI, L.P. and Cypress Investments, LLC.	8-K	001-35049	10.3	April 18, 2022
10.34	Lock-up Agreement dated April 14, 2022, by and between Earthstone Energy, Inc. and Bighorn Permian Resources, LLC.	8-K	001-35049	10.4	April 18, 2022
10.35	Voting Agreement dated as of April 14, 2022, by and among Earthstone Energy, Inc., Cypress Investments, LLC, 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, L.P., Warburg Pincus Energy (E&P) Partners-A, L.P., Warburg Pincus Energy (E&P) Partners-B IRH, LLC, WP Energy Partners IRH Holdings, L.P., WP Energy IRH Holdings, L.P., WP Energy Chisholm Holdings, L.P., WP Energy Partners Chisholm Holdings, L.P., Warburg Pincus Energy (E&P) Partners-B Chisholm, LLC, Warburg Pincus Private Equity (E&P) XII (A), L.P., WP XII Chisholm Holdings, L.P., Warburg Pincus XII (E&P) Partners-2 Chisholm, LLC, Warburg Pincus Private Equity (E&P) XII-D (A), L.P., Warburg Pincus Private Equity (E&P) XII-E (A), L.P., Warburg Pincus XII (E&P) Partners-1, L.P., and WP XII (E&P) Partners (A), L.P.	8-K	001-35049	10.5	April 18, 2022
10.36	Registration Rights Agreement dated August 10, 2022, by and among Earthstone Energy, Inc., Titus Oil & Gas, LLC, and Titus Oil & Gas Investments II, LLC.	8-K	001-35049	10.1	August 11, 2022
10.37	Form of Lock-up Agreement.	8-K	001-35049	10.2	August 11, 2022
10.38†	Form of Performance Unit Agreement (Annualized TSR).	8-K	001-35049	10.1	January 12, 2023
10.39†	Form of Performance Unit Agreement (Relative TSR).	8-K	001-35049	10.2	January 12, 2023
10.40†	Form of Restricted Stock Unit Agreement.	8-K	001-35049	10.3	January 12, 2023
10.41†	Form of Restricted Stock Unit Agreement (non-employee director).	8-K	001-35049	10.4	January 12, 2023
14.1	Code of Business Conduct and Ethics.					X
21.1	List of Subsidiaries.					X
23.1	Consent of Cawley, Gillespie & Associates, Inc.					X

	~~Page~~
~~Audited Financial Statements:~~		Page

Report of Independent Registered Public Accounting Firm ( Moss Adams LLP, Houston Texas, PCAOB ID: 659)		F-2
~~Report of Independent Registered Public Accounting Firm~~ Audited Financial Statements:		~~F-3~~
Consolidated Balance Sheets as of December 31, ~~2017~~2022 and ~~2016~~2021		~~F-4~~ F-5
Consolidated Statements of Operations for the Years Ended December 31, ~~2017, 2016~~2022, 2021 and ~~2015~~2020		~~F-5~~ F-7
Consolidated Statements of Equity for the Years Ended December 31, ~~2017, 2016~~2022, 2021 and ~~2015~~2020		~~F-6~~ F-8
Consolidated Statements of Cash Flows for the Years Ended December 31, ~~2017, 2016~~2022, 2021 and ~~2015~~2020		~~F-7~~ F-9
Notes to Consolidated Financial Statements		~~F-8~~ F-10
Unaudited Information:
Supplemental Information on Oil and Gas Exploration and Production Activities		~~S-1~~ F-42


	December 31,							December 31,
ASSETS	2017			2016			ASSETS	2022		2021
Current assets:							Current assets:
Cash	$	22,955		$	10,200		Cash	$	—	$	4,013
Accounts receivable:							Accounts receivable:
Oil, natural gas, and natural gas liquids revenues		14,978			13,998		Oil, natural gas, and natural gas liquids revenues	161,531		50,575
Joint interest billings and other, net of allowance of $138 and $163 at December 31, 2017 and 2016, respectively		7,778			2,698
Joint interest billings and other, net of allowance of $19 and $19 at December 31, 2022 and 2021, respectively							Joint interest billings and other, net of allowance of $19 and $19 at December 31, 2022 and 2021, respectively	34,549		2,930
Derivative asset		184			—		Derivative asset	31,331		1,348
Prepaid expenses and other current assets		1,178			446		Prepaid expenses and other current assets	18,854		2,549
Total current assets		47,073			27,342		Total current assets	246,265		61,415

Oil and gas properties, successful efforts method:							Oil and gas properties, successful efforts method:
Proved properties		605,039			363,072		Proved properties	3,987,901		1,625,367
Unproved properties		275,025			51,723		Unproved properties	282,589		222,025
Land		5,534			—		Land	5,482		5,382
Total oil and gas properties		885,598			414,795		Total oil and gas properties	4,275,972		1,852,774

Accumulated depreciation, depletion and amortization		(118,028	)		(145,393	)	Accumulated depreciation, depletion and amortization	(619,196)		(395,625)
Net oil and gas properties		767,570			269,402		Net oil and gas properties	3,656,776		1,457,149

Other noncurrent assets:							Other noncurrent assets:
Goodwill		17,620			17,620
Office and other equipment, net of accumulated depreciation of $2,093 and $1,600 at December 31, 2017 and 2016, respectively		947			1,479

Office and other equipment, net of accumulated depreciation of $5,273 and $4,547 at December 31, 2022 and 2021, respectively							Office and other equipment, net of accumulated depreciation of $5,273 and $4,547 at December 31, 2022 and 2021, respectively	5,394		1,986
Derivative asset							Derivative asset	9,117		157
Operating lease right-of-use assets							Operating lease right-of-use assets	4,569		1,795
Other noncurrent assets		1,207			669		Other noncurrent assets	15,280		33,865
TOTAL ASSETS	$	834,417		$	316,512		TOTAL ASSETS	$	3,937,401	$	1,556,367
LIABILITIES AND EQUITY							LIABILITIES AND EQUITY
Current liabilities:							Current liabilities:
Accounts payable	$	33,472		$	11,927		Accounts payable	$	91,815	$	31,397
Revenues and royalties payable		10,288			10,769		Revenues and royalties payable	163,368		36,189
Accrued expenses		8,707			5,392		Accrued expenses	80,942		31,704
Asset retirement obligation							Asset retirement obligation	948		395
Derivative liability		11,805			4,595		Derivative liability	14,053		45,310
Advances		4,587			4,542		Advances	7,312		4,088
Current portion of long-term debt		—			1,604
Operating lease liability							Operating lease liability	842		681
Finance lease liability							Finance lease liability	802		—
Other current liabilities							Other current liabilities	16,202		851

Total current liabilities		68,859			38,829		Total current liabilities	376,284		150,615

Noncurrent liabilities:							Noncurrent liabilities:
Long-term debt		25,000			12,693		Long-term debt	1,053,879		320,000
Asset retirement obligation		2,354			6,013		Asset retirement obligation	29,611		15,471
Derivative liability		1,826			1,575		Derivative liability	—		571
Deferred tax liability		10,515			15,776		Deferred tax liability	138,336		15,731
Operating lease liability							Operating lease liability	3,889		1,276
Finance lease liability							Finance lease liability	876		—
Other noncurrent liabilities		131			169		Other noncurrent liabilities	10,509		6,442
Total noncurrent liabilities		39,826			36,226		Total noncurrent liabilities	1,237,100		359,491

Commitments and Contingencies (Note 15)							Commitments and Contingencies (Note 15)

Equity:							Equity:
Preferred stock, $0.001 par value, 20,000,000 shares authorized; none issued or outstanding		—			—		Preferred stock, $0.001 par value, 20,000,000 shares authorized; none issued or outstanding	—		—
Common stock, $0.001 par value, no shares authorized; none issued or outstanding at December 31, 2017 and 100,000,000 shares authorized; 22,289,177 issued and 22,273,820 outstanding at December 31, 2016		—			23
Class A Common stock, $0.001 par value, 200,000,000 shares authorized; 27,584,638 issued and outstanding at December 31, 2017; none issued or outstanding at December 31, 2016		28			—
Class B Common stock, $0.001 par value, 50,000,000 shares authorized; 36,052,169 issued and outstanding at December 31, 2017; none issued or outstanding at December 31, 2016		36			—
Additional paid-in capital		503,932			454,202
Accumulated deficit		(224,822	)		(212,308	)
Treasury stock, no shares at December 31, 2017 and 15,357 shares at December 31, 2016		—			(460	)
Total Earthstone Energy, Inc. equity		279,174			241,457
Noncontrolling interest		446,558			—
Total equity		725,732			241,457
Series A Convertible Preferred Stock, $0.001 par value, none authorized, issued or outstanding							Series A Convertible Preferred Stock, $0.001 par value, none authorized, issued or outstanding	—		—

TOTAL LIABILITIES AND EQUITY	$	834,417		$	316,512
Class A Common Stock, $0.001 par value, 200,000,000 shares authorized; 105,547,139 and 53,467,307 issued and outstanding at December 31, 2022 and 2021, respectively							Class A Common Stock, $0.001 par value, 200,000,000 shares authorized; 105,547,139 and 53,467,307 issued and outstanding at December 31, 2022 and 2021, respectively	106		53


Class B Common Stock, $0.001 par value, 50,000,000 shares authorized; 34,259,641 and 34,344,532 issued and outstanding at December 31, 2022 and 2021, respectively	34		34
Additional paid-in capital	1,346,463		718,181
Retained Earnings (accumulated deficit)	292,711		(159,774)

Total Earthstone Energy, Inc. equity	1,639,314		558,494
Noncontrolling interest	684,703		487,767
Total equity	2,324,017		1,046,261

TOTAL LIABILITIES AND EQUITY	$	3,937,401	$	1,556,367


	Issued Shares
	Common Stock			Class A Common Stock			Class B Common Stock			Common Stock			Class A Common Stock		Class B Common Stock		Additional Paid-in Capital			Accumulated Deficit			Treasury Stock			Total Earthstone Energy, Inc. Stockholders' Equity			Noncontrolling Interest			Total Equity
At December 31, 2014		13,835,128			—			—		$	14		$	—	$	—	$	358,086		$	(41,112	)	$	(460	)	$	316,528		$	—		$	316,528

Net loss		—			—			—			—			—		—		—			(116,655	)		—			(116,655	)		—			(116,655	)
At December 31, 2015		13,835,128			—			—			14			—		—		358,086			(157,767	)		(460	)		199,873			—			199,873

Stock-based compensation expense		—			—			—			—			—		—		3,301			—			—			3,301			—			3,301
Common stock issued, net of offering costs of $2.7 million		4,753,770			—			—			5			—		—		47,120			—			—			47,125			—			47,125
Shares issued in Lynden Arrangement		3,700,279			—			—			4			—		—		45,695			—			—			45,699			—			45,699
Net loss		—			—			—			—			—		—		—			(54,541	)		—			(54,541	)		—			(54,541	)
At December 31, 2016		22,289,177			—			—			23			—		—		454,202			(212,308	)		(460	)		241,457			—			241,457

Stock-based compensation expense		—			—			—			—			—		—		6,601			—			—			6,601			—			6,601
Vesting of restricted stock units prior to completion of Bold Contribution Agreement		382,804			—			—			—			—		—		(1	)		—			—			(1	)					(1	)
Common stock exchanged in connection with Bold Contribution Agreement		(22,656,624	)		22,656,624			—			(23	)		23		—		—			—			—			—			—			—
Treasury shares converted to Class A Common Stock		(15,357	)		15,357			—			—			—		—		—			—			—			—			—			—
Closing of Bold Contribution Agreement		—			150,000			—			—			—		—		12,872			—						12,872			479,007			491,879
Class B Common Stock sold in connection with Bold Contribution Agreement		—			—			36,070,828			—			—		36		—			—			—			36			—			36
Deferred tax consequences of Bold Contribution Agreement		—			—			—			—			—		—		(8,270	)		—			—			(8,270	)		—			(8,270	)
Vesting of restricted stock units following completion of Bold Contribution Agreement		—			259,355			—			—			—		—		—			—			—			—			—			—
Class A Common Stock retained by the Company in exchange for payment of recipient mandatory tax withholdings		—			61,055			—			—			—		—		(675	)		—			—			(675	)		—			(675	)
Cancellation of treasury shares		—			(76,412	)		—			—			—		—		(460	)		—			460			—			—			—
Class A Common Stock issued, net of offering costs of $2.2 million		—			4,500,000			—			—			5		—		39,433			—			—			39,438			—			39,438
Class B Common Stock converted to Class A Common Stock		—			18,659			(18,659	)		—			—		—		230			—			—			230			(230	)		—
Net loss		—			—			—			—			—		—		—			(12,514	)		—			(12,514	)		(32,219	)		(44,733	)
At December 31, 2017		—			27,584,638			36,052,169		$	—		$	28	$	36	$	503,932		$	(224,822	)	$	—		$	279,174		$	446,558		$	725,732


	Issued Shares
	Series A Convertible Preferred Stock	Class A Common Stock	Class B Common Stock	Series A Convertible Preferred Stock		Class A Common Stock		Class B Common Stock		Additional Paid-in Capital		Accumulated Deficit		Earthstone Energy, Inc. Equity		Noncontrolling Interest		Total Equity








At December 31, 2019	—	29,421,131	35,260,680	$	—	$	29	$	35	$	527,246	$	(181,711)	$	345,599	$	490,152	$	835,751

Stock-based compensation expense	—	—	—	—		—		—		10,054		—		10,054		—		10,054
Vesting of restricted stock units, net of taxes paid	—	670,981	—	—		1		—		(1)		—		—		—		—
Vested restricted stock units retained by the Company in exchange for payment of recipient mandatory tax withholdings	—	243,924	—	—		—		—		(835)		—		(835)		—		(835)
Cancellation of treasury shares	—	(243,924)	—	—		—		—		—		—		—		—		—
Class B Common Stock converted to Class A Common Stock	—	251,309	(251,309)	—		—		—		3,610		—		3,610		(3,610)		—
Net loss	—	—	—	—		—		—		—		(13,547)		(13,547)		(15,887)		(29,434)
At December 31, 2020	—	30,343,421	35,009,371	$	—	$	30	$	35	$	540,074	$	(195,258)	$	344,881	$	470,655	$	815,536
Stock-based compensation expense	—	—	—	—		—		—		9,132		—		9,132		—		9,132
Modification of performance units	—	—	—	—		—		—		(2,276)		—		(2,276)		—		(2,276)
Shares issued in connection with IRM Acquisition	—	12,719,594	—	—		13		—		76,559		—		76,572		—		76,572
Shares issued in connection with Tracker Acquisition	—	6,200,000	—	—		6		—		61,808		—		61,814		—		61,814
Shares issued in connection with Foreland Acquisition	—	2,611,111	—	—		2		—		28,119		—		28,121		—		28,121
Vesting of restricted stock units, net of taxes paid	—	928,342	—	—		1		—		(1)		—		—		—		—
Class A Shares retained by the Company in exchange for payment of recipient mandatory tax withholdings	—	453,483	—	—		—		—		(4,144)		—		(4,144)		—		(4,144)
Cancellation of treasury shares	—	(453,483)	—	—		—		—		—		—		—		—		—
Class B Common Stock converted to Class A Common Stock	—	664,839	(664,839)	—		1		(1)		8,910		—		8,910		(8,910)		—
Net income	—	—	—	—		—		—		—		35,484		35,484		26,022		61,506
At December 31, 2021	—	53,467,307	34,344,532	$	—	$	53	$	34	$	718,181	$	(159,774)	$	558,494	$	487,767	$	1,046,261
Stock-based compensation expense	—	—	—	—		—		—		16,733		—		16,733		—		16,733
Purchase of treasury shares	—	(3,000,000)	—	—		(3)		—		(43,934)		—		(43,937)		—		(43,937)
Preferred stock issuance	280,000	—	—	—		—		—		279,326		—		279,326		—		279,326
Conversion of preferred stock	(280,000)	25,225,225	—	—		25		—		(25)		—		—		—		—
Shares issued in connection with Chisholm Acquisition	—	19,417,476	—	—		19		—		249,495		—		249,514		—		249,514
Shares issued in connection with Bighorn Acquisition	—	5,650,977	—	—		6		—		77,752		—		77,758		—		77,758
Shares issued in connection with Titus Acquisition	—	3,857,015	—	—		4		—		53,570		—		53,574		—		53,574
Vesting of restricted stock units, net of taxes paid	—	844,248	—	—		2		—		(2)		—		—		—		—
Class A Shares retained by the Company in exchange for payment of recipient mandatory tax withholdings	—	429,547	—	—		—		—		(5,829)		—		(5,829)		—		(5,829)
Cancellation of Treasury shares	—	(429,547)	—	—		—		—		—		—		—		—		—
Class B Common Stock converted to Class A Common Stock	—	84,891	(84,891)	—		—		—		1,196		—		1,196		(1,196)		—
Net income	—	—	—	—		—		—		—		452,485		452,485		198,132		650,617
At December 31, 2022	—	105,547,139	34,259,641	—		106		34		1,346,463		292,711		1,639,314		684,703		2,324,017


	EEH Units Held By Earthstone and Lynden US	%		EEH Units Held By Others	%		Total EEH Units Outstanding
As of December 31, 2021	53,467,307	60.9	%	34,344,532	39.1	%	87,811,839
EEH Units issued in connection with the Chisholm Acquisition	19,417,476			—			19,417,476
EEH Units issued in connection with the Bighorn Acquisition	5,650,977			—			5,650,977
EEH Units issued in connection with the Conversion of Preferred Stock	25,225,225			—			25,225,225
EEH Units issued in connection with the Titus Acquisition	3,857,015			—			3,857,015
EEH Units and shares of Class B Common Stock exchanged for shares of Class A Common Stock	84,891			(84,891)			—
EEH Units issued in connection with the vesting of restricted stock units	844,248			—			844,248
EEH Units cancelled in connection with the share repurchase	(3,000,000)			—			(3,000,000)
As of December 31, 2022	105,547,139	75.5	%	34,259,641	24.5	%	139,806,780

Consideration:
Shares of Class A Common Stock issued pursuant to the Bold Contribution Agreement to certain employees of Bold		150,000
EEH Units issued to Bold Holdings		36,070,828

Total equity interest issued in the Bold Transaction		36,220,828
Closing per share price of Class A Common Stock as of May 9, 2017	$	13.58

Total consideration transferred ^{(1) (2)}	$	491,879

Fair value of assets acquired:
Cash and cash equivalents	$	2,355
Other current assets		10,078
Oil and gas properties ⁽³⁾		557,704
Amount attributable to assets acquired	$	570,137

Fair value of liabilities assumed:
Long-term debt ⁽⁴⁾	$	58,000
Current liabilities		17,042
Deferred tax liability		2,857
Noncurrent asset retirement obligations		359
Amount attributable to liabilities assumed	$	78,258


Consideration:
Shares of Class A Common Stock issued	3,857,015
Class A Common Stock price as of August 10, 2022	$	13.89
Class A Common Stock consideration	53,574
Cash consideration	566,532
Direct transaction costs (1)	1,144
Total consideration transferred	$	621,250

Fair value of assets acquired:
Oil and gas properties	$	625,017
Amount attributable to assets acquired	$	625,017

Fair value of liabilities assumed:
Current liabilities	$	2,853
Noncurrent liabilities - ARO	914
Amount attributable to liabilities assumed	$	3,767


	Total
Consideration:
Shares of Earthstone Class A Common Stock issued	6,200,000
Earthstone Class A Common Stock price as of July 20, 2021	$	9.97
Class A Common Stock consideration	$	61,814
Cash consideration (1)	60,159
Direct transaction costs (2)	1,715
Total consideration transferred	$	123,688

Fair value of assets acquired:
Oil and gas properties	$	124,288
Amount attributable to assets acquired	$	124,288

Fair value of liabilities assumed:
Noncurrent liabilities - ARO	$	600
Amount attributable to liabilities assumed	$	600


December 31, 2017	Level 1		Level 2		Level 3		Total
December 31, 2022									December 31, 2022	Level 1		Level 2		Level 3		Total
Financial assets									Financial assets
Derivative asset- current	$	—	$	184	$	—	$	184	Derivative asset- current	$	—	$	31,331	$	—	$	31,331
Derivative asset- noncurrent									Derivative asset- noncurrent	—		9,117		—		9,117
Total financial assets	$	—	$	184	$	—	$	184	Total financial assets	$	—	$	40,448	$	—	$	40,448
Financial liabilities									Financial liabilities
Derivative liability - current									Derivative liability - current	$	—	$	14,053	$	—	$	14,053

Share-based compensation liability - current									Share-based compensation liability - current	—		14,411		—		14,411
Share-based compensation liability - noncurrent									Share-based compensation liability - noncurrent	—		10,357		—		10,357
Total financial liabilities									Total financial liabilities	$	—	$	38,821	$	—	$	38,821
December 31, 2021									December 31, 2021
Financial assets									Financial assets
Derivative asset- current									Derivative asset- current	$	—	$	1,348	$	—	$	1,348
Derivative asset- noncurrent									Derivative asset- noncurrent	—		157		—		157
Total financial assets									Total financial assets	$	—	$	1,505	$	—	$	1,505
Financial liabilities									Financial liabilities
Derivative liability - current	$	—	$	11,805	$	—	$	11,805	Derivative liability - current	$	—	$	45,310	$	—	$	45,310
Derivative liability - noncurrent		—		1,826		—		1,826	Derivative liability - noncurrent	—		571		—		571
Share-based compensation liability - current									Share-based compensation liability - current	—		7,835		—		7,835
Share-based compensation liability - noncurrent									Share-based compensation liability - noncurrent	—		6,324		—		6,324
Total financial liabilities	$	—	$	13,631	$	—	$	13,631	Total financial liabilities	$	—	$	60,040	$	—	$	60,040

December 31, 2016
Financial liabilities
Derivative liability - current	$	—	$	4,595	$	—	$	4,595
Derivative liability - noncurrent		—		1,575		—		1,575
Total financial liabilities	$	—	$	6,170	$	—	$	6,170