Earthstone Energy

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
____________________________________________________
FORM 10-K
____________________________________________________
(Mark One)
☑
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the Fiscal Year Ended December 31, 2022
Or
☐
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
Commission File No. 001-35049  
____________________________________________________
EARTHSTONE ENERGY, INC.
(Exact name of registrant as specified in its charter)
____________________________________________________
Delaware
 
84-0592823
(State or other jurisdiction
of incorporation or organization)
 
(I.R.S. Employer
Identification No.)
1400 Woodloch Forest Drive, Suite 300
The Woodlands, Texas 77380
(Address of principal executive offices)
Registrant’s telephone number, including area code: (281) 298-4246
Securities registered pursuant to Section 12(b) of the Act:
Title of each class
Trading Symbol
Name of each exchange on which registered
Class A Common Stock, $0.001 par value per share
ESTE
New York Stock Exchange  (NYSE)
Securities registered under Section 12(g) of the Act:
None
____________________________________________________
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes ☐ No ☑
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or 15(d) of the Exchange Act. Yes ☐ No ☑
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 
12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to the filing requirements for the past 90 days. Yes ☑ No 
☐
Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation 
S-T during the preceding 12 months (or for such shorter period that the registrant was required to post such files). Yes ☑ No ☐
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth 
company. See the definitions of “large accelerated filer”, “accelerated filer”, “smaller reporting company” and “emerging growth company” in Rule 12b-2 of the Exchange 
Act:
Large accelerated filer
☐
  
Accelerated filer
☑
Non-accelerated filer
☐ 
  
Smaller reporting company
☐
Emerging growth Company
☐
 
 
 
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial 
accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐
Indicate by check mark whether the registrant has filed a report on and attestation to its management’s assessment of the effectiveness of its internal control over financial 
reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C. 7262(b)) by the registered public accounting firm that prepared or issued its audit report. ☑
If securities are registered pursuant to Section 12(b) of the Act, indicate by check mark whether the financial statements of the registrant included in the filing reflect the 
correction of an error to previously issued financial statements. ☐
Indicate by check mark whether any of those error corrections are restatements that required a recovery analysis of incentive-based compensation received by any of the 
registrant’s executive officers during the relevant recovery period pursuant to §240.10D-1(b). ☐
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ☐ No ☑
The aggregate market value of voting and non-voting common equity held by non-affiliates computed by reference to the price of $13.65 per share at which the common 
equity was last sold, as of the last business day of the registrant’s most recently completed second fiscal quarter was approximately $586,314,541.

As of March 2, 2023, there were 140,443,172 shares of common stock outstanding, including 106,183,531 shares of Class A Common Stock, $0.001 par value per share, and 
34,259,641 shares of Class B Common Stock, $0.001 par value per share.
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the Registrant’s Definitive Proxy Statement for its 2023 Annual Meeting of Stockholders (the “Proxy Statement”), are incorporated by reference into Part III of 
this Annual Report on Form 10-K.

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

CAUTIONARY STATEMENT CONCERNING FORWARD-LOOKING STATEMENTS
Certain statements contained in this report may contain “forward-looking statements” within the meaning of Section 27A of the 
Securities Act of 1933, as amended (the “Securities Act”), and Section 21E of the Securities Exchange Act of 1934, as amended 
(the “Exchange Act”). All statements other than statements of historical facts contained in this report are forward-looking 
statements. These forward-looking statements can generally be identified by the use of words such as “may,” “will,” “could,” 
“should,” “project,” “intends,” “plans,” “pursue,” “target,” “continue,” “believes,” “anticipates,” “expects,” “estimates,” 
“guidance,” “possible,” “probable,” “predicts,” or “potential,” the negative of such terms or variations thereon, or other 
comparable terminology. Statements that describe our future plans, strategies, intentions, expectations, objectives, goals, 
potential acquisitions or mergers or prospects are also forward-looking statements. Actual results could differ materially from 
those anticipated in this filing or these forward-looking statements. Readers should consider carefully the risks described under 
the “Risk Factors” section of this report and other sections of this report which describe factors that could cause our actual 
results to differ from those anticipated in forward-looking statements, including, but not limited to, the following factors:
•
continued volatility in commodity prices for oil, natural gas and natural gas liquids and the effect of prices set 
or influenced by action of the Organization of Petroleum Exporting Countries (“OPEC”), its members and 
other oil and natural gas producing countries;
•
the effect of existing and future laws, governmental regulations and the political and economic trends of the 
United States particularly with respect to climate change, alternative energy and similar topical movements;
•
substantial changes in estimates of our proved reserves;
•
the effects of inflation on our cost structure;
•
substantial declines in the estimated values of our proved oil and natural gas reserves;
•
our ability to replace our oil and natural gas reserves;
•
impacts of world health events, including the coronavirus and variants (“COVID-19”) and possible similar 
events or pandemics in the future;
•
the effects of rising interest rates on our cost of capital and the actions that central banks around the world 
undertake to control inflation, including the impacts such actions have on general economic conditions;
•
the risk of the actual presence or recoverability of oil and natural gas reserves and that future production rates 
may be less than estimated;
•
the potential for production decline rates and associated production costs for our wells to be greater than we 
forecast;
•
the timing and extent of our success in acquiring, discovering, developing and producing oil and natural gas 
reserves; 
•
the financial ability and willingness of our partners under our joint operating agreements to join in our plans 
for future exploration, development and production activities;
•
our ability to acquire additional mineral leases;
•
the cost and availability of high-quality equipment and services with fully trained and adequate personnel, 
such as contract drilling rigs and completion equipment on a timely basis and at reasonable prices;
•
risks in connection with potential acquisitions and the integration of significant acquisitions or assets acquired 
through merger or otherwise;
•
the possibility that acquisitions and divestitures may involve unexpected costs or delays, and that acquisitions 
may not achieve intended benefits;
•
the possibility that potential divestitures may not occur or could be burdened with unforeseen costs;
•
unanticipated reductions in the borrowing base under the credit agreement we are party to;
•
our ability to comply with restrictions contained in our credit agreement and the indenture governing our 
senior unsecured notes, as well as debt incurred in the future; 
•
our ability to generate sufficient cash to service our indebtedness, fund our capital expenditures and generate 
future profits;
•
risks incidental to the drilling and operation of oil and natural gas wells including mechanical failures;
4

•
our dependence on the availability, use and disposal of water in our drilling, completion and production 
operations;
•
the availability of sufficient pipeline and other transportation facilities to carry our production to market and 
the impact of these facilities on realized prices;
•
significant competition for oil and natural gas acreage and acquisitions;
•
our ability to retain key members of senior management and key technical and financial employees;
•
changes in environmental laws and the regulation and enforcement related to those laws;
•
the identification of and severity of adverse environmental events and governmental responses to these or 
other environmental events;
•
legislative or regulatory changes, including retroactive royalty or production tax regimes, hydraulic-fracturing 
regulations, derivatives reform, and changes in federal and state income taxes;
•
future ESG compliance developments and increased attention to such matters which could adversely affect 
our ability to raise equity and debt capital;
•
future cyber risk compliance developments and its effect on the loss of confidentiality, integrity, or 
availability of information, data, or information (or control) systems that reflect the potential adverse impacts 
to organizational operations and assets, individuals, and other organizations;
•
general economic conditions, whether internationally, nationally or in the regional and local market areas in 
which we conduct business, may be less favorable than expected, including the possibility that economic 
conditions in the United States could deteriorate and that capital markets for equity and debt could be 
disrupted or unavailable;
•
social unrest, political instability or armed conflict in major oil and natural gas producing regions outside the 
United States and acts of terrorism or sabotage;
•
our insurance coverage may not adequately cover all losses that may be sustained in connection with our 
business activities;
•
other economic, competitive, governmental, regulatory, legislative, including federal and state regulations and 
laws, geopolitical and technological factors that may negatively impact our business, operations or oil and 
natural gas prices;
•
the effect of our oil and natural gas derivative activities;
•
title to the properties in which we have an interest may be impaired by title defects;
•
our dependency on the skill, ability and decisions of third-party operators of oil and natural gas properties in 
which we have non-operated working interests; and
•
possible adverse results from litigation and the use of financial resources to defend ourselves.
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.
5

GLOSSARY OF CERTAIN OIL AND NATURAL GAS TERMS
The following are abbreviations and definitions of terms commonly used in the oil and natural gas industry and within this 
report.
3-D seismic – An advanced technology method of detecting accumulation of hydrocarbons identified through a three-
dimensional picture of the subsurface created by the collection and measurement of the intensity and timing of sound waves 
transmitted into the earth as they reflect back to the surface.
Bbl – One barrel or 42 U.S. gallons liquid volume of oil or other liquid hydrocarbons.
Bcf – One billion cubic feet of natural gas.
Boe – Barrel of oil equivalent, determined using a ratio of six Mcf of natural gas equal to one barrel of oil equivalent. The ratio 
does not assume price equivalency and, given price differentials, the price for a barrel of oil equivalent for natural gas differs 
significantly from the price for a barrel of oil. A barrel of natural gas liquids also differs significantly in price from a barrel of 
oil.
Boepd – Boe per day.
Btu – British thermal unit, the quantity of heat required to raise the temperature of one pound of water by one-degree 
Fahrenheit.
Completion – The process of treating and hydraulically fracturing a drilled well followed by the installation of permanent 
equipment for the production of oil or natural gas, or in the case of a dry hole, the reporting of abandonment to the appropriate 
regulatory agency.
Developed acreage – The number of acres which are allotted or assignable to producing wells or wells capable of production.
Development activities – Activities following exploration including the drilling and completion of additional wells and the 
installation of production facilities.
Development well – A well drilled within the proved area of an oil or natural gas reservoir to the depth of a stratigraphic 
horizon known to be productive.
Dry hole or well – A well found to be incapable of producing hydrocarbons economically.
ESG – Environmental, Social and Governance.
Exploitation – A development or other project which may target proven or unproven reserves (such as probable or possible 
reserves), but which generally has a lower risk than that associated with exploration projects.
Exploration – encompasses the processes and methods involved in locating potential sites for oil and natural gas drilling and 
extraction. 
Exploratory well – A well drilled to find and produce oil or natural gas reserves in an area or a potential reservoir not classified 
as proved.
Field – An area consisting of a single reservoir or multiple reservoirs all grouped on or related to the same individual geological 
structural feature and/or stratigraphic condition.
Gross acres or gross wells – The total acres or wells, as the case may be, in which a working interest is owned.
Horizontal drilling – A drilling technique that permits the operator to drill horizontally within a specified targeted reservoir and 
thus exposes a larger portion of the producing horizon to a wellbore than would otherwise be exposed through conventional 
vertical drilling techniques.
Hydraulic fracture or Frac – A well stimulation method by which fluid, comprised largely of water and proppant (purposely 
sized particles used to hold open an induced fracture) is injected downhole and into the producing formation at high pressures 
and rates in order to exceed the rock strength and create a fracture such that the proppant material can be placed into the fracture 
to enhance the productive capability of the formation.
Injection well – A well which is used to inject gas, water, or liquefied petroleum gas under high pressure into a producing 
formation to maintain sufficient pressure to produce the recoverable reserves.
Joint Operating Agreement or JOA – Any agreement between working interest owners concerning the duties and 
responsibilities of the operator and rights and obligations of the non-operators.
MBbls – One thousand barrels of crude oil or other liquid hydrocarbons.
6

MBoe – One thousand barrels of oil equivalent, determined using a ratio of six Mcf of natural gas equal to one barrel of oil 
equivalent.
MMBoe – One million barrels of oil equivalent, determined using a ratio of six Mcf of natural gas equal to one barrel of oil 
equivalent.
MMBtu – One million Btu.
Mcf – One thousand cubic feet.
MMcf – One million cubic feet.
Natural gas liquids – Natural gas liquids measured in barrels. Natural gas liquids are made up of ethane, propane, isobutane, 
normal butane and natural gasoline, each of which have different uses and different pricing characteristics.
Net acres or net wells – The sum of the fractional working interests owned in gross acres or gross wells.
NYMEX – The New York Mercantile Exchange.
Plugging and abandonment or P&A – Refers to the sealing off of fluids in the strata penetrated by a well so that the fluids 
from one stratum will not escape into another stratum or to the surface.
PV-10 – The present value of estimated future revenues, discounted at 10% annually, to be generated from the production of 
proved reserves determined in accordance with the SEC guidelines, net of estimated production and future development costs, 
using prices and costs as of the date of estimation without future escalation, without giving effect to (i) non-property related 
expenses such as general and administrative expenses, debt service and future income tax expense, or (ii) depreciation, 
depletion and amortization.
Productive well – A well that is found to be capable of producing hydrocarbons in sufficient quantities such that proceeds from 
the sale of such production exceeds production expenses and taxes.
Proppant – A solid material, typically treated sand or man-made ceramic materials, designed to keep an induced hydraulic 
fracture open, during or following a fracturing treatment.
Proved developed nonproducing reserves or PDNP – Hydrocarbons in a potentially producing horizon penetrated by a 
wellbore, the production of which has been postponed pending completion activities and the installation of surface equipment 
or gathering facilities or pending the production of hydrocarbons from another formation penetrated by the wellbore. The 
hydrocarbons are classified as proved developed but nonproducing reserves.
Proved developed producing reserves or PDP – Reserves that can be expected to be recovered from existing wells and 
completions with existing equipment and operating methods.
Proved developed reserves or PD – The estimated quantities of oil, natural gas and natural gas liquids that geological and 
engineering data demonstrate with reasonable certainty to be commercially recoverable in future years from known reservoirs 
under existing economic and operating conditions.
Proved reserves – Those quantities of oil and natural gas, which, by analysis of geoscience and engineering data, can be 
estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs, and 
under existing economic conditions, operating methods, and government regulations—prior to the time at which contracts 
providing the right to operate expire, unless evidence indicates that renewal is reasonably certain.
Proved undeveloped reserves or PUD – Proved reserves that are expected to be recovered from new wells on undrilled acreage 
or from existing wells where a relatively major expenditure is required for recompletion.
Recompletion – The completion for production of an existing well bore in another formation from that in which the well has 
been previously completed.
Re-engineering – A process involving a comprehensive review of the mechanical conditions associated with wells and 
equipment in producing fields. Our re-engineering practices typically result in a capital expenditure plan which is implemented 
over time to workover (see below) and re-complete wells and modify down hole artificial lift equipment and surface equipment 
and facilities. The programs are designed specifically for individual fields to increase and maintain production, reduce down-
time and mechanical failures, lower per-unit operating expenses, and therefore, improve field economics.
Reservoir – A permeable underground formation containing a natural accumulation of producible oil and/or natural gas that is 
confined by impermeable rock or water barriers and is individual and separate from other reservoirs.
Royalty interest – An interest in an oil and natural gas property entitling the owner to a share of oil or natural gas production 
free of costs of production.
7

SEC – United States Securities and Exchange Commission.
Shut-in reserves – Those reserves expected to be recovered from completion intervals that were open at the time the reserve 
was estimated but were not producing due to market conditions, mechanical difficulties or because production equipment or 
pipelines were not yet installed. These reserves are included in the PDNP category in our reserve report.
SOFR – Secured Overnight Financing Rate. 
Standardized Measure – The present value of estimated future net revenue to be generated from the production of proved 
reserves, determined in accordance with the rules and regulations of the SEC (using prices and costs in effect as of the date of 
estimation), less future development, production and income tax expenses, and discounted at 10% per annum to reflect the 
timing of future net revenue.
Undeveloped acreage – Lease acreage on which wells have not been drilled or completed to a point that would permit the 
production of commercial quantities of oil and natural gas regardless of whether such acreage contains proved reserves.
Working interest or WI – The ownership interest, generally defined in a JOA, that gives the owner the right to drill, produce 
and/or conduct operating activities on the property and share in the sale of production, subject to all royalties, overriding 
royalties and other burdens and obligates the owner of the interest to share in all costs of exploration, development operations 
and all risks in connection therewith.
Workover – Operations on a producing well to restore or increase production.
WTI – West Texas Intermediate light sweet crude oil, a benchmark in crude oil pricing.
8

PART I
Item 1. Business
Overview
Earthstone Energy, Inc., a Delaware corporation (“Earthstone” and together with our consolidated subsidiaries, the “Company,” 
“our,” “we,” “us,” or similar terms), is a growth-oriented independent oil and gas company engaged in the acquisition and 
development of oil and gas reserves through activities that include drilling and development of undeveloped leases, as well as 
asset and corporate acquisitions and mergers. Our operations are all in the upstream segment of the oil and natural gas industry 
and all our properties are onshore in the United States. Our primary assets are located in the Midland Basin in West Texas and 
the Delaware Basin in New Mexico.
2022 Highlights 
The following are highlights of our 2022 activities: 
•
Closed the Titus Acquisition in the Delaware Basin on August 10, 2022
•
Closed the Bighorn Acquisition in the Midland Basin on April 14, 2022
•
Closed the Chisholm Acquisition in the Delaware Basin on February 15, 2022
•
Repurchased 3.0 million shares of Class A Common Stock for $43.7 million
•
Full year 2022 average daily sales volumes of 78,167 Boepd exceeded our production goals and increased 
215% over 2021
•
Maintained strong balance sheet and liquidity position with $679.9 million of undrawn capacity on our 
$1.2 billion senior credit facility as of December 31, 2022
•
Continued development of our properties which included drilling 75 gross / 58.9 net operated wells and 
completing 56 gross / 46.5 net operated wells
For the three acquisitions that we closed during 2022, we spent a total of approximately $1.5 billion, net of customary purchase 
price adjustments, and issued 28,925,468 shares of our Class A common stock, $0.001 par value per share of Earthstone (the 
“Class A Common Stock”), with an acquisition date fair value of $380.8 million. In the aggregate, these acquisitions added 
significant scale by expanding our Permian Basin acreage footprint by approximately 66% gross / 48% net, increasing our 
estimated proved reserves by 213.1 MMBoe as well as increasing our sales volumes by 16.7 MMBoe for the year then ended.
Organizational Structure
Earthstone is the sole managing member of Earthstone Energy Holdings, LLC, a subsidiary of Earthstone (“EEH”). Earthstone, 
together with its wholly-owned subsidiary, Lynden Energy Corp., a corporation organized under the laws of British Columbia 
(“Lynden Corp”), and Lynden Corp’s wholly-owned consolidated subsidiary, Lynden USA Inc. (“Lynden US”), collectively 
own a 75.5% interest in EEH. We consolidate the financial results of EEH and present a noncontrolling interest in the 
Consolidated Financial Statements representing the economic interests of EEH’s members other than Earthstone and Lynden 
US. Each of the outstanding shares of Class A Common Stock 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 collectively represent the 
noncontrolling interests in Consolidated Financial Statements. 
At any time, at the holder’s discretion, a holder of an EEH Unit may receive a share of Class A Common Stock in exchange for 
an EEH Unit and a corresponding share of Class B Common Stock, resulting in the immediate cancellation of both the EEH 
Unit and share of Class B Common Stock exchanged. As of December 31, 2022, outstanding common shares of Earthstone, 
along with the equal number of corresponding outstanding EEH Units, were approximately 139.8 million, consisting of 105.5 
million shares of Class A Common Stock and 34.3 million shares of Class B Common Stock.
9

The following diagram indicates our simplified ownership structure as of the date of this report. This diagram is provided for 
illustrative purposes only and does not represent all legal entities affiliated with us.
Recent Developments
Share Repurchase
On October 11, 2022, Earthstone repurchased an aggregate of 3,000,000 shares of Class A Common Stock, held by affiliates of 
Warburg Pincus LLC (“Warburg”) in a private transaction, for an aggregate purchase price of approximately $43.7 million, or 
$14.58 per share. 
Titus Acquisition
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 Titus Acquisition (“Titus Cash Consideration”), net of 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 
10

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.
Conversion of Series A Convertible Preferred Stock
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.
Credit Agreement 
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.
11

Bighorn Acquisition
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, which includes approximately $2.3 million in 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.
Securities Purchase Agreement 
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.
Notes Offering
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. 
Chisholm Acquisition
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.
12

Cash consideration for the Chisholm Acquisition was funded by borrowings under the Credit Agreement.
Inflation
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. 
Our Properties
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 our operated properties. Independent contractors engaged by us provide all the 
equipment and personnel associated with drilling and completion activities. We employ petroleum engineers, geologists and 
land professionals who work on improving drilling and completion processes, operating 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. 
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.
Overall
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.
Midland Basin
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. 
Delaware Basin
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 Business Strategy 
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We believe that the recent trend of consolidation in the industry environment will continue and will result in further 
consolidation opportunities. We continue to pursue value-accretive and scale-enhancing consolidation opportunities, as we 
believe we are in a position to operate effectively despite volatility in commodity prices. We are focusing our attention on 
acquisition and corporate merger opportunities that would increase the scale of our operations in a financially accretive manner, 
without materially altering our debt metrics in relation to our cash flows and capital structure. In addition, we believe that our 
recent track record of successful consolidation will create further consolidation opportunities for us based on our increased 
scale, financial strength and success at acquiring and integrating assets in a financially prudent manner. At the same time, we 
will seek to block up acreage in the Midland Basin and Delaware Basin that would allow for longer horizontal laterals and 
should therefore provide for higher economic returns. In summary, we believe we are well qualified to be a consolidator which 
would increase the scale of our operations and add value to our shareholders.
Our current business strategy is to focus on the economic development of our existing acreage, increase our acreage and 
horizontal well locations in the Midland and Delaware Basins and increase stockholder value through the following:
•
developing our acreage and profitably growing our production while seeking to maximize operating cash 
flows;
•
operating our properties efficiently and continuing to improve our operating margins;
•
deploying capital efficiently by drilling multi-well pads, reducing drilling times and increasing completions 
per day;
•
leveraging both our increased operational and financial scale to achieve economies related to such scale 
where available;
•
operating our assets in a safe and environmentally sensitive manner;
•
continuing to hedge commodity prices as opportunities arise;
•
pursuing value-accretive acquisition and corporate merger opportunities, which could increase the scale and 
profitability of our operations;
•
maximizing operating margins and corporate level cash flows by minimizing operating and overhead costs;
•
expanding our acreage positions and drilling inventory in our primary areas of interest through acquisitions 
and farm-in opportunities, with an emphasis on operated positions;
•
blocking up acreage to allow for longer horizontal lateral drilling locations which provide higher economic 
returns; and
•
maintaining a strong balance sheet and financial flexibility.
Our Strengths
We believe that the following strengths are beneficial in achieving our business goals:
•
history of successful asset acquisitions and merger transactions;
•
extensive horizontal development potential in two of the most oil rich basins of the United States;
•
experienced management team with substantial technical and operational expertise;
•
ability to attract technical personnel with experience in our core area of operations;
•
operating control over the majority of our production and development activities;
•
financial discipline;
•
effectively managing leverage;
•
commitment to cost efficient operations;
•
a management team that is well known and respected throughout the industry; and
•
ability to efficiently integrate acquisitions, allowing us to improve operating margins, as well as reducing lead 
time on additional acquisition opportunities.
COVID-19
Despite the recoveries in commodity prices, COVID-19 may continue to impact the global economy, disrupt supply chains and 
may create significant volatility and disruption of financial and commodity markets. The potential future impact of COVID-19 
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on our operational and financial performance, including our ability to fully execute our business strategies and efficiently 
operate our properties is uncertain and depends on numerous non-controllable factors. A material resurgence of COVID-19 may 
impact the demand for oil and natural gas, the availability of personnel, equipment and services critical to the operation of our 
properties. There is significant uncertainty around the extent and duration of disruptions from any such resurgence, but we 
expect that the longer the disruption, the greater the adverse impact may be on our business. 
Operational Status
As a producer of oil, natural gas and natural gas liquids, we are recognized as an essential business under various federal, state 
and local regulations related to COVID-19. The safety of our employees is paramount, and we have emphasized the respective 
guidelines to support our mitigation efforts. Our field personnel have performed their job responsibilities with no issues to date.  
We required full-time office attendance for non-field personnel during 2021 and 2022, but remained flexible to working 
remotely, if needed. We will continue to focus on the health and safety of our employees in conformity with the applicable 
jurisdictional mitigation guidelines. 
Operational/Financial Challenges
It is difficult to model and predict how our operations and financial status may change as a result of COVID-19. In our industry, 
any forecast, plans and changes to operations and financial status are a function of commodity prices, inflationary pressures and 
prevailing capital and operating costs. If oil and gas prices decline significantly due to a resurgence of COVID-19, we believe 
we can take immediate steps to operate and produce our properties at least in a cash flow neutral position for the next 12 
months. If a material resurgence of COVID-19 triggered a substantial adverse response from banks and financial institutions, 
our borrowing base could be reduced, resulting in a borrowing base deficiency in relation to outstanding debt which may lead to 
a default. 
Operational Risks
Oil and natural gas exploitation, development and production involve a high degree of risk, which even a combination of 
experience, knowledge and careful evaluation may not be able to overcome. There is no assurance that we will acquire, 
discover or produce additional oil and natural gas in commercial quantities. Oil and natural gas operations also involve the risk 
that well fires, blowouts, equipment failure, human error and other events may cause accidental leakage or spills of toxic or 
hazardous materials, such as petroleum liquids or drilling fluids into the environment or cause significant injury to persons or 
property. In such event, substantial liabilities to third parties or governmental entities may be incurred, the satisfaction of which 
could substantially reduce our available cash and possibly result in loss of oil and natural gas properties. Such hazards may also 
cause damage to or destruction of wells, producing formations, production facilities and pipeline or other processing facilities.
As is common in the oil and natural gas industry, we do not insure fully against all risks associated with our business either 
because such insurance is not available or because we believe the premium costs are prohibitive. A loss not fully covered by 
insurance could have a material effect on our operating results, financial position and cash flows. For further discussion of these 
risks see Item 1A. Risk Factors of this report.
Marketing and Customers
We market the majority of the production from properties we operate for both our account and the account of the other working 
interest owners in these properties. We sell our production to purchasers at market prices.
We normally sell production to a relatively small number of customers, as is customary in the exploration, development and 
production business. For the year ended December 31, 2022, three purchasers accounted for 21%, 20% and 14%, respectively, 
of our revenue during the period. For the year ended December 31, 2021, two purchasers accounted for 34% and 13%, 
respectively, of our revenue during the period. For the year ended December 31, 2020, three purchasers accounted for 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 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.
15

Transportation and Gathering
During the planning stage of our prospective and productive units and acreage, we consider required flow-lines, gathering and 
delivery infrastructure. Our oil is transported from the wellhead to our tank batteries or delivery points through our flow-lines or 
gathering systems. Purchasers of our oil take delivery (i) at a pipeline delivery point or (ii) at our tank batteries for transport by 
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 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 saltwater disposal wells or by pipeline to 
commercial disposal facilities.
Commodity Hedging
Consistent with our disciplined approach to financial management, we have an active commodity hedging program through 
which we seek to hedge a meaningful portion of our expected oil and gas production, reducing our exposure to downside 
commodity prices and enabling us to protect cash flows and maintain liquidity to fund our capital program.
Competition
The domestic oil and natural gas industry is intensely competitive in the acquisition of acreage, production and oil and gas 
reserves and in producing, transporting and marketing activities. Our competitors include national oil companies, major oil and 
natural gas companies, independent oil and natural gas companies, drilling partnership programs, individual producers, natural 
gas marketers, and major pipeline companies, as well as participants in other industries supplying energy and fuel to consumers. 
Many of our competitors are large, well-established companies. They may be able to pay more for seismic information and 
lease rights on 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.
Segment Information and Geographic Area
Operating segments are defined under accounting principles generally accepted in the United States (“GAAP”) as components 
of an enterprise that (i) engage in activities from which it may earn revenues and incur expenses (ii) for which separate 
operational financial information is available and is regularly evaluated by the chief operating decision maker for the purpose of 
allocating resources and assessing performance.
Based on our organization and management, we have only one reportable operating segment, which is oil and natural gas 
acquisition, exploration, development and production. All of our operations are currently conducted in Texas and New Mexico.
Seasonality of Business
Weather conditions often affect the demand for, and prices of, natural gas and can also delay oil and natural gas drilling, 
completion and production activities, disrupting our overall business plans. Demand for natural gas is typically higher during 
the winter, resulting in higher natural gas prices for our natural gas production during our first and fourth fiscal quarters. Due to 
these seasonal fluctuations, our results of operations for individual quarterly periods may not be indicative of the results that we 
may realize on an annual basis.
Markets for Sale of Production
Our ability to market oil and natural gas found and produced, depends on numerous factors beyond our control, the effect of 
which cannot be accurately predicted or anticipated. Some of these factors include, without limitation, the availability of other 
16

domestic and foreign production, the marketing of competitive fuels, the proximity and capacity of pipelines, fluctuations in 
supply and demand, the availability of a ready market, the effect of United States federal and state regulation of production, 
refining, transportation and sales and general national and worldwide economic conditions. Additionally, we may experience 
delays in marketing natural gas production and fluctuations in natural gas prices and we may experience short-term delays in 
marketing oil due to trucking and refining constraints. There is no assurance that we will be able to market 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 view of the many uncertainties affecting the supply and demand for oil, natural gas and natural gas liquids, we are unable to 
accurately predict future oil, natural gas and 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.
Title to Properties
We believe that the title to our oil and natural gas properties is good and defensible in accordance with standards generally 
accepted in the oil and natural gas industry, subject to such exceptions which, in our opinion, are not so material as to detract 
substantially from the use or value of our oil and natural gas properties. Our oil and natural gas properties are typically subject, 
in one degree or another, to one or more of the following:
•
royalties and other burdens and obligations, express or implied, under oil and natural gas leases;
•
overriding royalties and other burdens created by us or our predecessors in title;
•
a variety of contractual obligations (including, in some cases, development obligations) arising under 
operating agreements, farmout agreements, participation agreements, production sales contracts and other 
agreements that may affect the properties or their titles;
•
back-ins and reversionary interests existing under various agreements and leasehold assignments;
•
liens that arise in the normal course of operations, such as those for unpaid taxes, statutory liens securing 
obligations to unpaid suppliers and contractors and contractual liens under operating agreements;
•
pooling, unitization and other agreements, declarations and orders; and
•
easements, restrictions, rights-of-way and other matters that commonly affect property.
To the extent that such burdens and obligations affect our rights to production revenues, they have been taken into account in 
calculating our net revenue interests and in estimating the quantity and value of our reserves. We believe that the burdens and 
obligations affecting our oil and natural gas properties are common in our industry with respect to the types of properties we 
own.
Operational Regulations
All of the jurisdictions in which we own or operate producing oil and natural gas properties have statutory and regulatory 
provisions affecting drilling, completion, and production activities, including, but not limited to, provisions related to permits 
for the drilling of wells, bonding requirements to drill or operate wells, the location of wells, the method of drilling and casing 
wells, the surface use and restoration of properties upon which wells are drilled, sourcing and disposal of water used in the 
drilling and completion process, and the plugging and abandonment of wells. 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 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 
17

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.
Regulation of Transportation of Natural Gas
The transportation and sale, or resale, of natural gas in interstate commerce are regulated by the Federal Energy Regulatory 
Commission (“FERC”) under the Natural Gas Act of 1938 (“NGA”), the Natural Gas Policy Act of 1978 (“NGPA”) and 
regulations issued under those statutes. FERC regulates interstate natural gas transportation rates and service conditions, which 
affects the marketing of natural gas that we produce, as well as the revenues we receive for sales of our natural gas.
Intrastate natural gas transportation is also subject to regulation by state regulatory agencies. The basis for intrastate regulation 
of natural gas transportation and the degree of regulatory oversight and scrutiny given to intrastate natural gas pipeline rates and 
services varies from state to state. Insofar as such regulation within a particular state will generally affect all intrastate natural 
gas shippers within the state on a comparable basis, we believe that the regulation of similarly situated intrastate natural gas 
transportation in any states in which we operate and ship natural gas on an intrastate basis will not affect our operations in any 
way that is of material difference from those of our competitors. Like the regulation of interstate transportation rates, the 
regulation of intrastate transportation rates affects the marketing of natural gas that we produce, as well as the revenues we 
receive for sales of our natural gas.
Regulation of Sales of Oil, Natural Gas and Natural Gas Liquids
The prices at which we sell oil, natural gas and natural gas liquids are not currently subject to federal regulation and, for the 
most part, are not subject to state regulation. FERC, however, regulates interstate natural gas transportation rates, and terms and 
conditions of transportation service, which affects the marketing of the natural gas we produce, as well as the prices we receive 
for sales of our natural gas. Similarly, the price we receive from the sale of oil and natural gas liquids is affected by the cost of 
transporting those products to market. FERC regulates the transportation of oil and liquids on interstate pipelines under the 
provision of the Interstate Commerce Act, the Energy Policy Act of 1992 and regulations issued under those statutes. Intrastate 
transportation of oil, natural gas liquids, and other products, is dependent on pipelines whose rates, terms and conditions of 
service are subject to regulation by state regulatory bodies under state statutes. In addition, while sales by producers of natural 
gas and all sales of crude oil, condensate, and natural gas liquids can currently be made at uncontrolled market prices, Congress 
could reenact price controls in the future. 
Changes in FERC or state policies and regulations or laws may adversely affect the availability and reliability of firm and/or 
interruptible transportation service on interstate pipelines, and we cannot predict what future action that FERC or state 
regulatory bodies will take. We do not believe, however, that any regulatory changes will affect us in a way that materially 
differs from the way they will affect other natural gas producers, gatherers and marketers with which we compete.
Environmental Regulations
Our operations are also subject to stringent federal, state and local laws regulating the discharge 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 
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summary of the more significant existing environmental, health and safety laws and regulations to which our business 
operations are subject and for which compliance in the future may have a material adverse impact on our capital expenditures, 
earnings and competitive position.
Hazardous Substances and Wastes
The federal Comprehensive Environmental Response, Compensation, and Liability Act of 1980 (“CERCLA”), also known as 
the Superfund law, and comparable state laws impose liability, without regard to fault or the legality of the original conduct on 
certain categories of persons that are considered to be responsible for the release 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 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. A loss of the RCRA exclusion for drilling fluids, produced waters and related wastes could result in an 
increase in our, as well as the oil and natural gas E&P industry’s, costs to manage and dispose of generated wastes, which could 
have a material adverse effect on the industry as well as on our business.
From time to time, releases of materials or wastes have occurred at locations we own or at which we have operations. These 
properties and the materials or wastes released thereon may be subject to CERCLA, RCRA and analogous state laws. Under 
these laws, we have been and may be required to remove or remediate such materials or wastes.
Water Discharges
The federal Clean Water Act and analogous state laws impose restrictions and strict controls with respect to the discharge of 
pollutants, including spills and leaks of oil and other substances, into waters of the United States. The discharge of pollutants 
into regulated waters, including jurisdictional wetlands, is prohibited, except in accordance with the terms of a permit issued by 
the EPA or an analogous state agency. In January 2023, the EPA and the Corps issued a final rule that revises the definition of 
“waters of the United States”. The final rule has been challenged by several states and industry groups. As a result of these 
developments, the 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, 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 
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criminal penalties for unauthorized discharges and, together with the Oil Pollution Act of 1990 (“OPA”), impose rigorous 
requirements for spill prevention and response planning, as well as substantial potential liability for the costs of removal, 
remediation, and damages in connection with any unauthorized discharges.
Our oil and natural gas production also generates salt water, which we dispose of by underground injection. The federal Safe 
Drinking Water Act (“SDWA”) regulates the underground injection of substances through the Underground Injection Control 
(“UIC”) program, and related state programs regulate the drilling and operation of saltwater disposal wells. The EPA directly 
administers the UIC program in some states, and in others it is delegated to the state for administering. In New Mexico, the 
New Mexico Oil Conservation Division (“NMOCD”) administers the UIC program for all injection wells that are related to oil 
and natural gas production. In Texas, the Texas Railroad Commission (“RRC”) regulates the disposal of produced water by 
injection well. Permits must be obtained before drilling saltwater disposal wells, and casing integrity monitoring must be 
conducted periodically to ensure the casing is not leaking salt water to groundwater. Contamination of groundwater by oil and 
natural gas drilling, production, and related operations may result in fines, penalties, and remediation costs, among other 
sanctions and liabilities under the SDWA and state laws. In response to recent seismic events near underground injection wells 
used for the disposal of oil and natural gas-related waste waters, federal and some state agencies have begun investigating 
whether such wells have caused increased seismic activity, and some states have shut down or placed volumetric injection 
limits on existing wells or imposed moratoria on the use of such injection wells. In response to concerns related to induced 
seismicity, regulators in some states have already adopted or are considering additional requirements related to seismic safety. 
For example, the RRC has adopted rules for injection wells to address these seismic activity concerns in Texas. Among other 
things, the rules require companies seeking permits for disposal wells to provide seismic activity data in permit applications, 
provide for more frequent monitoring and reporting for certain wells and allow the RRC to modify, suspend, or terminate 
permits on grounds that a disposal well is likely to be, or determined to be, causing seismic activity. 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. More stringent 
regulation of injection wells could lead to reduced construction or the capacity of such wells, which could in turn impact the 
availability of injection wells for disposal of wastewater from our operations. Increased costs associated with the transportation 
and disposal of produced water, including the cost of complying with regulations concerning produced water disposal, may 
reduce our profitability. The costs associated with the disposal of proposed water are commonly incurred by all oil and natural 
gas producers, however, and we do not believe that these costs will have a material adverse effect on our operations. In 
addition, third-party claims may be filed by landowners and other parties claiming damages for alternative water supplies, 
property damages, and bodily injury.
Hydraulic Fracturing
Our completion operations are subject to regulation, which may increase in the short- or long-term. In particular, the well 
completion technique known as hydraulic fracturing which is used to stimulate production of oil and natural gas has come 
under increased scrutiny by the environmental community, and many local, state and federal regulators. Hydraulic fracturing 
involves the injection of water, sand and additives under pressure, usually down casing that is cemented in the wellbore, into 
prospective rock formations in order to stimulate oil and natural gas production. We engage third parties to provide hydraulic 
fracturing or other well stimulation services to us in connection with substantially all of the wells for which we are the operator.
The SDWA regulates the underground injection of substances through the UIC program. Hydraulic fracturing is generally 
exempt from regulation under the UIC program, and the hydraulic fracturing process is typically regulated by state oil and gas 
commissions. However, legislation has been proposed in recent sessions of Congress to amend the SDWA to repeal the 
exemption for hydraulic fracturing from the definition of “underground injection,” to require federal permitting and regulatory 
control of hydraulic fracturing, and to require disclosure of the chemical constituents of the fluids used in the fracturing process.
Furthermore, several federal agencies have asserted regulatory authority over certain aspects of the fracturing process. For 
example, the EPA has taken the position that hydraulic fracturing with fluids containing diesel fuel is subject to regulation 
under the UIC program, specifically as “Class II” UIC wells.
In addition, on June 28, 2016, the EPA published a final rule prohibiting the discharge of wastewater from onshore 
unconventional oil and natural gas extraction facilities to publicly owned wastewater treatment plants. The EPA is also 
conducting a study of private wastewater treatment facilities (also known as centralized waste treatment (“CWT”) facilities) 
accepting oil and natural gas extraction wastewater. The EPA is collecting data and information related to the extent to which 
CWT facilities accept such wastewater, available treatment technologies (and their associated costs), discharge characteristics, 
financial characteristics of CWT facilities, and the environmental impacts of discharges from CWT facilities.
Furthermore, there are certain governmental reviews either underway or being proposed that focus on environmental aspects of 
hydraulic fracturing practices. On December 13, 2016, the EPA released a study examining the potential for hydraulic 
fracturing activities to impact drinking water resources, finding that, under some circumstances, the use of water in hydraulic 
fracturing activities can impact drinking water resources. Also, on February 6, 2015, the EPA released a report with findings 
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and recommendations related to public concern about induced seismic activity from disposal wells. The report recommends 
strategies for managing and minimizing the potential for significant injection-induced seismic events. Other governmental 
agencies, including the U.S. Department of Energy, the U.S. Geological Survey, and the U.S. Government Accountability 
Office, have evaluated or are evaluating various other aspects of hydraulic fracturing. These ongoing or proposed studies could 
spur initiatives to further regulate hydraulic fracturing and could ultimately make it more difficult or costly for us to perform 
fracturing and increase our costs of compliance and doing business.
Several states, including Texas, have adopted or are considering adopting regulations that could restrict or prohibit hydraulic 
fracturing in certain circumstances, impose more stringent operating standards and/or require the disclosure of the composition 
of hydraulic fracturing fluids. For example, Texas law requires that the well operator disclose the list of chemical ingredients 
subject to the requirements of the federal Occupational Safety and Health Act (“OSHA”) for disclosure on a website and also 
file the list of chemicals with the RRC with the well completion report. The total volume of water used to hydraulically fracture 
a well must also be disclosed to the public and filed with the RRC. 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.
There has been increasing public controversy regarding hydraulic fracturing with regard to the use of fracturing fluids, induced 
seismic activity, impacts on drinking water supplies, use of water and the potential for impacts to surface water, groundwater 
and the environment generally. Several lawsuits and enforcement actions have been initiated across the country implicating 
hydraulic fracturing practices. If new laws or regulations that significantly restrict hydraulic fracturing are adopted, such laws 
could make it more difficult or costly for us to perform fracturing to stimulate production from tight formations as well as make 
it easier for third parties opposing the hydraulic fracturing process to initiate legal proceedings based on allegations that specific 
chemicals used in the fracturing process could adversely affect groundwater. In addition, if hydraulic fracturing is further 
regulated at the federal, state or local level, our fracturing activities could become subject to additional permitting and financial 
assurance requirements, more stringent construction specifications, increased monitoring, reporting and recordkeeping 
obligations, plugging and abandonment requirements and also to attendant permitting delays and potential increases in costs. 
Such legislative changes could cause us to incur substantial compliance costs, and compliance or the consequences of any 
failure to comply by us could have a material adverse effect on our financial condition and results of operations. At this time, it 
is not possible to estimate the impact on our business of newly enacted or potential federal, state or local laws governing 
hydraulic fracturing.
From time to time, legislation has been introduced, but not enacted, in the U.S. Congress to provide for federal regulation of 
hydraulic fracturing and to require disclosure of the chemicals used in the hydraulic fracturing process. On January 28, 2020, 
Senate Bill 3247 was introduced and if enacted as proposed, would ban hydraulic fracturing nationwide by 2025.
Air Emissions
The federal Clean Air Act (“CAA”) and comparable state laws restrict emissions of various air pollutants through permitting 
programs and the imposition of other requirements. In addition, the EPA has developed and continues to develop 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 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. On May 12, 2016, the EPA amended its regulations to impose new standards for 
methane and volatile organic compounds emissions for certain new, modified, and reconstructed equipment, processes, and 
activities across the oil and natural gas sector. However, in a March 28, 2017 executive order, the Trump Administration 
directed the EPA to review the 2016 regulations and, if appropriate, to initiate a rule making to rescind or revise them consistent 
with the stated policy of promoting clean and safe development of the nation’s energy resources, while at the same time 
avoiding regulatory burdens that unnecessarily encumber energy production. In September 2020, the EPA finalized 
amendments to the 2016 standards that removed the transmission and storage segment from the oil and natural gas source 
category and rescinded the methane-specific requirements for production and processing facilities. However, President Biden 
signed an executive order on his first day in office calling for the suspension, revision, or rescission of the September 2020 rule 
and the reinstatement or issuance of methane emission standards for new, modified, and existing oil and gas facilities. Given the 
long-term trend toward increasing regulation, future federal Greenhouse Gas (“GHG”) regulations of the oil and gas industry 
remain a possibility, and several states have separately imposed their own regulations on methane emissions from oil and gas 
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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 eliminate venting of associated gas and requirements for 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 “Super-Emitter Response Program.” The EPA 
expects to finalize its new methane rules in 2023. The foregoing laws, regulations, 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. Until 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 (“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, however, could revive the effort in the future. In 2022, the 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 NAAQs for 
ozone. As of the effective date, these rules apply to oil and natural gas production in 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 areas of state implementation of 
NAAQS, or designation of areas in which we 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 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 be 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 oversight related to flaring, with reporting reviews and site 
inspections. While none of these activities increases our compliance obligations, they signal the potential for increased 
enforcement and possible rulemaking in the future.
Climate Change
In response to findings that emissions of carbon dioxide, methane and other GHGs endanger public health and the environment, 
the EPA has adopted regulations under existing provisions of the CAA that, among other things, establish construction and 
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operating permit reviews for GHG emissions certain large stationary sources, require the monitoring and annual reporting of 
GHG emissions from certain petroleum and natural gas system sources in the United States, implement New Source 
Performance Standards directing the reduction of methane from certain new, modified, or reconstructed facilities in the oil and 
natural gas sector, and together with the Department of Transportation (the “DOT”), implement GHG emissions limits on 
vehicles manufactured for operation in the United States. Additionally, various states and groups of states have adopted or are 
considering adopting legislation, regulations or other regulatory initiatives that are focused on such areas as GHG cap and trade 
programs, carbon taxes, reporting and tracking programs, and restriction of emissions. At the international level, there is an 
agreement, the United Nations-sponsored “Paris Agreement,” for nations to limit their GHG emissions through non-binding, 
individually determined reduction goals every five years after 2020.The United States rejoined the Paris Agreement in February 
2021. In early 2021, the Biden Administration issued a moratorium on oil and gas leasing on federal lands and waters to reduce 
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 November 2021, the United States participated in the 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 “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 Climate Change Conference in Egypt 
(“COP27”). Although it is not possible at this time to predict what additional domestic legislation may be adopted in light of the 
Paris Agreement or the Glasgow Climate Pact, or how legislation or new regulations that may be adopted based on the Paris 
Agreement or the Glasgow Climate Pact to address GHG emissions would impact our 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 and production companies in state or federal court, alleging, among other things, that 
such companies created public nuisances by producing fuels that contributed to global warming effects, such as rising sea 
levels, and therefore are responsible for roadway and infrastructure damages, or alleging that the companies have been aware of 
the adverse effects of climate change for some time but defrauded their investors by failing to adequately disclose those 
impacts.
There are also increasing financial risks for fossil fuel producers as shareholders currently invested in fossil-fuel energy 
companies concerned about the potential effects of climate change may elect in the future to shift some or all of their 
investments into non-energy related sectors. Institutional lenders who provide financing to fossil-fuel energy companies also 
have become more attentive to sustainable lending practices and some of them may elect not to provide funding for fossil fuel 
energy companies. Additionally, the lending practices of institutional lenders have been the subject of intensive lobbying efforts 
in recent years, oftentimes public in nature, by environmental activists, proponents of the international Paris Agreement, and 
foreign citizenry concerned about climate change not to provide funding for fossil fuel producers. Limitation of investments in 
and financings for fossil fuel energy companies could result in the restriction, delay or cancellation of drilling programs or 
development or production activities.
The adoption and implementation of new or more stringent international, federal or state legislation, regulations or other 
regulatory initiatives that impose more stringent standards for GHG emissions from the oil and natural gas sector or otherwise 
restrict the areas in which this sector may produce oil and natural gas or generate GHG emissions could result in increased costs 
of compliance or costs of consuming, and thereby reduce demand for, oil and natural gas. In early 2023, for example, legislators 
in New Mexico introduced a bill that, if enacted, would significantly revise the state’s 1935 Oil & Gas Act by, among other 
things, removing the $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 justice 
advisory council. Additionally, political, litigation and financial risks may result in us restricting or cancelling production 
activities, incurring liability for infrastructure damages as a result of climatic changes, or having an impaired ability to continue 
to operate in an economic manner. One or more of these developments could have a material adverse effect on our business, 
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financial condition and results of operation. We also are aware that the SEC intends to propose new and additional rules 
regarding company disclosure of climate change risk. We will monitor and comply with any such promulgated rules.
Threatened and endangered species, migratory birds and natural resources
Various federal and state statutes prohibit certain actions that adversely affect endangered or threatened species and their 
habitat, migratory birds, wetlands, and natural resources. These statutes include the Endangered Species Act (“ESA”), the 
Migratory Bird Treaty Act (“MBTA”) and the Clean Water Act. The U.S. Fish and Wildlife Service (“FWS”) may designate 
critical habitat areas that it believes are necessary for survival of threatened or endangered species. As a result of a 2011 
settlement agreement, the FWS was required to determine whether to identify more than 250 species as endangered or 
threatened under the 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 protected status under the ESA pursuant to the settlement agreement. A critical 
habitat designation could result in further material restrictions on federal land use or on private land use and could delay or 
prohibit land access or development. Where takings of or harm to species or damages to wetlands, habitat, or natural resources 
occur or may occur, government entities or at times private parties may act to prevent or restrict oil and natural gas exploration 
activities or seek damages for any injury, whether resulting from drilling or construction or releases of oil, wastes, hazardous 
substances or other regulated materials, and in some cases, criminal penalties may result. Similar protections are offered to 
migratory birds under the MBTA. Recently, there have been renewed calls to review protections currently in place for the dunes 
sagebrush lizard, whose habitat includes portions of the Permian Basin, and to reconsider listing the species under the ESA. 
While some of our operations may be located in areas that are designated as habitats for endangered or threatened species or 
that may attract migratory birds, we believe that we are in substantial compliance with the ESA and the MBTA, and we are not 
aware of any proposed ESA listings that will materially affect our operations. 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 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.
Hazard communications and community right to know
We are subject to federal and state hazard communication and community right to know statutes and regulations. These 
regulations, including, but not limited to, the federal Emergency Planning & Community Right-to-Know Act, govern record 
keeping and reporting of the use and release of hazardous substances and may require that information be provided to state and 
local government authorities, as well as the public.
Occupational Safety and Health Act
We are subject to a number of federal and state laws and regulations, including OSHA, and comparable state statutes that 
regulate the protection of the health and safety of workers. In addition, OSHA hazard communication standard requires that 
information be maintained about hazardous materials used or produced in operations and that this information be provided to 
employees, state and local government authorities and citizens.
State Regulation
Texas 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 impose a severance 
tax on oil production of 4.6% and 3.75%, respectively, and a severance tax on natural gas 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 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.
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The petroleum industry is also subject to compliance with various other federal, state and local regulations and laws. Some of 
those laws relate to resource conservation and equal employment opportunity. We do not believe that compliance with these 
laws will have a material adverse effect on us.
Related Insurance
We maintain insurance against some risks associated with above or underground contamination that may occur as a result of 
our exploration, development and production activities. However, this insurance is limited to activities at the well site, and there 
can be no assurance that this insurance will continue to be commercially available or that this insurance will be available at 
premium levels that justify its purchase by us. The occurrence of a significant event that is not fully insured or indemnified 
against could have a materially adverse effect on our financial condition and operations.
Although we have not experienced any material adverse effect from compliance with environmental requirements, there is no 
assurance that this will continue. We did not have any material capital or other non-recurring expenditures in connection with 
complying with environmental laws or environmental remediation matters in 2022, nor do we anticipate that such expenditures 
will be material in 2023.
Human Capital Management
Employees
As of December 31, 2022, we had 219 full-time employees, of which 13 are management, 62 are technical personnel, 37 are 
administrative personnel and 107 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.
Health and Safety
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 believe that it is our responsibility to employ best practices for safety procedures and 
provide a safe workplace, as 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. 
Our Culture
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:
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A culture of empowerment, transparency, and cooperation is embraced
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All employees, customers, suppliers, and community members are treated fairly
•
Integrity and ethical behavior are demanded
•
Diversity of perspectives and ideas is acknowledged and valued
•
Communication is open and civil
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Conflict is addressed early and productively
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Professional and personal development is encouraged
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Teamwork is fostered
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Respect for others, the community and environment is valued
•
Collaboration and openness to new ideas is appreciated
Compensation and Benefits
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 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. 
Office Locations
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 Executive Officers
The following table sets forth, as of March 1, 2023, certain information regarding the executive officers of Earthstone:
Name
Age
Position
Frank A. Lodzinski
73
Executive Chairman of the Board
Robert J. Anderson
61
President and Chief Executive Officer
Tony Oviedo
69
Executive Vice President, Accounting and Administration
Mark Lumpkin, Jr.
49
Executive Vice President and Chief Financial Officer
Steven C. Collins
58
Executive Vice President, Chief Operating Officer
Timothy D. Merrifield
67
Executive Vice President, Geological and Geophysical
Robert W. Hunt, Jr
42
Executive Vice President, General Counsel
The following biographies describe the business experience of our executive officers:
Frank A. Lodzinski has over 50 years of oil and gas industry experience and served as our Chairman since December 2014 
and as Executive Chairman since April 1, 2020. He served as our Chief Executive Officer from December 2014 through March 
2020. He also served as our President from December 2014 through April 2018. Previously, he served as President and Chief 
Executive Officer of Oak Valley Resources LLC (“Oak Valley”) from its formation in December 2012 until the closing of its 
strategic combination with Earthstone in December 2014. Prior to his service with Oak Valley, Mr. Lodzinski was Chairman, 
President and Chief Executive Officer of GeoResources, Inc. from April 2007 until its merger with Halcón Resources 
Corporation (“Halcón”) in August 2012 and from September 2012 until December 2012 he conducted pre-formation activities 
for Oak Valley. From 1984 to 2004, he formed, acquired and/or managed several entities that were ultimately sold or merged 
into larger companies or were otherwise monetized for the benefit of shareholders. In 2004, Mr. Lodzinski formed Southern 
Bay Energy, LLC (“Southern Bay”) and served as its President. Through an affiliated limited partnership, Southern Bay 
acquired oil and gas assets. The Southern Bay entities were merged into GeoResources in April 2007. Mr. Lodzinski served as a 
26

director and member of various board committees of Yuma Energy, Inc. (“Yuma”) from September 2014 to October 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.
Robert J. Anderson has served as a director since July 2021. He has served as our President and Chief Executive Officer since 
April 2020, having previously served as President since April 2018. From December 2014 through April 2018, he served as our 
Executive Vice President, Corporate Development and Engineering. Previously, he served in a similar capacity with Oak Valley 
from March 2013 until the closing of its strategic combination with the Company in December 2014. Prior to joining Oak 
Valley, he served from August 2012 to February 2013 as Executive Vice President and Chief Operating Officer of Halcón. Mr. 
Anderson was employed by GeoResources, Inc. from April 2007 until its merger with Halcón in August 2012, ultimately 
serving as a director and Executive Vice President, Chief Operating Officer - Northern Region. He was involved in the 
formation of Southern Bay Energy in September 2004 as Vice President, Acquisitions until its merger with GeoResources in 
April 2007. From March 2004 to August 2004, Mr. Anderson was employed by AROC, a predecessor company to Southern 
Bay Energy, as Vice President, Acquisitions and Divestitures. Prior to March 2004, he was employed in technical and 
supervisory roles with Anadarko Petroleum Corporation, major oil companies including ARCO International/Vastar Resources, 
and independent oil companies, including Hugoton Energy, Hunt Oil and Pacific Enterprises Oil Company. His professional 
experience of over 30 years includes acquisition evaluation, reservoir and production engineering, field development, project 
economics, budgeting and planning, and capital markets. Mr. Anderson has a B.S. degree in Petroleum Engineering from the 
University of Wyoming and an MBA from the University of Denver. 
Tony Oviedo has served as our Executive Vice President - Accounting and Administration (Principal Accounting Officer) 
since February 10, 2017. Mr. Oviedo has over 41 years of professional experience with both private and public companies. 
Prior to joining the Company, he was employed by GeoMet, Inc., where, since 2006, he served as the Senior Vice President, 
Chief Financial Officer, Chief Accounting Officer and Controller. In addition, prior to joining GeoMet, Mr. Oviedo was 
employed by Resolution Performance Products, LLC, where he was Compliance Director and has held positions as Chief 
Accounting Officer, Controller, and Director of Financial Reporting with various companies in the oil and gas industry. Prior to 
the aforementioned experience, he served in the audit practice of KPMG LLP’s Energy Group. Mr. Oviedo holds a Bachelor’s 
degree in Business Administration with a concentration in accounting and tax from the University of Houston and is a Certified 
Public Accountant in the state of Texas.
Mark Lumpkin, Jr. has over 27 years of experience including over 18 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 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.
Steven C. Collins is a petroleum engineer with over 31 years of operations and related experience. He has served as our 
Executive Vice President and Chief Operating Officer since December 2014 (however, his title was Executive Vice President, 
Completions and Operations from December 2014 to January 2022 with the same position, authority and duties from December 
2014 to present). Previously, he served in a similar capacity with Oak Valley from its formation in December 2012 until the 
closing of its strategic combination with the Company in December 2014. Mr. Collins was employed by GeoResources, Inc. 
from April 2007 until its merger with Halcón in August 2012 and directed field operations, including well completion, 
production and workover operations. Prior to employment by GeoResources, he served as Vice President of Operations for 
Southern Bay, AROC, and Texoil, and as a petroleum and operations engineer at Hunt Oil Company and Pacific Enterprises Oil 
Company. His experience includes Texas, Louisiana (onshore and offshore), North Dakota, Montana, and the Mid-Continent. 
Mr. Collins graduated with a B.S. degree in Petroleum Engineering from the University of Texas.
Timothy D. Merrifield has over 40 years of oil and gas industry experience. He has served as our Executive Vice President, 
Geology and Geophysics since December 2014. Previously, he served in a similar capacity with Oak Valley from its formation 
in December 2012 until the closing of its strategic combination with the Company in December 2014. Prior to employment by 
Oak Valley, he served from August 2012 to November 2012 as a consultant to Halcón upon its merger with GeoResources, Inc. 
in August 2012. From April 2007 to August 2012, Mr. Merrifield led all geology and geophysics efforts at GeoResources. He 
has held previous roles at AROC, Force Energy, Great Western Resources and other independents. His domestic experience 
includes Texas, Louisiana (onshore and offshore), North Dakota, Montana, New Mexico, Rocky Mountain States, and the Mid-
Continent. In addition, he has international experience in Peru and the East Irish Sea. Mr. Merrifield attended Texas Tech 
University.
27

Robert W. Hunt Jr. has over 17 years of legal experience in the oil and gas industry. He has served as Executive Vice 
President & General Counsel of Earthstone since April 2022. Prior to joining Earthstone, he served as Senior Vice President, 
General Counsel and Secretary of Indigo Natural Resources LLC from August 2016 until Indigo’s merger with Southwestern 
Energy Company in September 2021. From May 2010 until July 2016, Mr. Hunt worked for Cobalt International Energy, Inc., 
serving most recently as Associate General Counsel focusing primarily on capital markets and major transactions. Mr. Hunt 
began his career with Vinson & Elkins LLP, practicing corporate and securities law. Mr. Hunt holds a B.S. degree in Business 
Administration and Politics from Washington and Lee University and a J.D. degree from the University of Texas.
Available Information
Our principal executive offices are located at 1400 Woodloch Forest Drive, Suite 300, The Woodlands, Texas 77380. Our 
telephone number is (281) 298-4246. You can find more information about us at our website located at 
www.earthstoneenergy.com. Our Annual Report on Form 10-K, our Quarterly Reports on Form 10-Q, our Current Reports on 
Form 8-K and any amendments to those reports are available free of charge on or through our website, which is not part of this 
report. These reports are available as soon as reasonably practicable after we electronically file these materials with, or furnish 
them to, the SEC. The SEC maintains a website at www.sec.gov that contains reports, proxy and information statements, and 
other information regarding issuers that file electronically with the SEC, including us.
Item 1A. Risk Factors 
Our business is subject to various risks and uncertainties in the ordinary course of our business. The following summarizes 
significant risks and uncertainties that may adversely affect our business, financial condition or results of operations. We cannot 
assure you that any of the events discussed in the risk factors below will not occur. Further, the risks and uncertainties described 
below are not the only ones we face. Additional risks not presently known to us or that we currently deem immaterial may also 
materially affect our business. 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.
Summary Risk Factors
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.
General Business and Industry Risks
•
Volatility in prices for oil, natural gas and natural gas liquids; 
•
Our oil and natural gas reserves are estimated and may not reflect the actual volumes we will recover, and we 
may be required to write down the carrying value of our proved properties under accounting rules;
•
The borrowing base under our Credit Agreement is subject to periodic redetermination, and we are subject to 
interest rate risk under our Credit Agreement;
•
Restrictive covenants in certain of our existing and future debt instruments may limit our ability to respond to 
changes in market conditions or pursue business opportunities;
•
The impacts of inflationary pressures on our operating costs and capital expenditures;
•
Our ability to replace our oil and natural gas reserves;
•
Uncertainties associated with estimating reserves and future net cash flows;
•
Development of our reserves may take longer and may require higher levels of capital expenditures than we 
currently anticipate;
•
The standardized measure of discounted future net cash flows from our estimated proved reserves may not be 
the same as the current market value of our estimated oil and natural gas reserves;
•
Our level of success in development and production activities;
•
Acquired properties may not produce as projected;
•
Certain 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 of other operators;
•
Multi-well pad drilling may result in volatility in our operating results;
•
Unavailability or high cost of additional oilfield services;
•
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;
•
Ability to obtain required capital or financing on satisfactory terms;
•
A negative shift in stakeholder sentiment towards the oil and natural gas industry;
•
Our ability to obtain future hedges and effectiveness of our commodity derivative activities;
28

•
Competition in the oil and natural gas industry;
•
Inability to complete additional acquisitions;
•
Risks associated with recent transactions and exposure to contingent liabilities;
•
Ability to effectively manage our expanded operations;
•
Incurrence of substantial losses and liability claims as a result of our oil and gas operations, and risks our 
insurance may be inadequate to protect us against these losses;
•
Exposure to significant compliance costs and liabilities;
•
Effects of the COVID-19 pandemic and responses; 
•
Federal and state legislation and regulatory initiatives relating to hydraulic fracturing and water disposal 
wells;
•
Extreme weather conditions affecting our ability to conduct drilling, completion and production activities;
•
Adoption of climate change legislation or regulations restricting emissions of “greenhouse gases” and 
potential physical effects of climate change;
•
Restrictions on drilling activities intended to protect certain species of wildlife;
•
Geographic concentration of our operations;
•
Changes in tax laws and regulations;
•
Availability, use and disposal of water;
•
Changes to government regulation or administrative practices may have a negative impact on our ability to 
operate and our profitability;
•
Regulations that restrict our ability to acquire federal leases in the future;
•
The marketability of our production is dependent upon gathering, processing and transportation facilities;
•
New climate disclosure rules proposed by the SEC may increase our costs of compliance and adversely 
impact our business;
•
Failure of third parties to fulfill their commitments to our projects;
•
Incurrence of significant additional amounts of debt; 
•
Our business could be materially and adversely affected by security threats, including cybersecurity threats, 
and other disruptions;
•
Our ability to attract, train and retain qualified personnel; and 
•
We may be involved in, or our assets may be affected by, legal and regulatory proceedings that could result in 
substantial liabilities.
Risks Related to the Ownership of our Class A Common Stock
•
As a holding company and the sole manager of EEH our only material asset is our equity interest in EEH;
•
Our principal stockholders hold substantial voting power of our Common Stock;
•
Holders of Class B Common Stock have the right to exchange their EEH Units and shares of Class B 
Common Stock for our Class A Common Stock;
•
Future sales of our Class A Common Stock could reduce our stock price;
•
We have no current plans to pay dividends on our Class A Common Stock;
•
Our Board of Directors can, without stockholder approval, cause preferred stock to be issued on terms that 
could adversely affect our common stockholders;
•
The price of our Class A Common Stock may fluctuate significantly;
•
Anti-takeover provisions could make a third-party acquisition difficult; and
•
Our stockholders may act by unilateral written consent.
General Business and Industry Risks
Oil, natural gas and natural gas liquid prices are volatile. Their prices at times have adversely affected, and in the future 
may adversely affect, our business, financial condition and results of operations and our ability to meet our capital 
expenditure obligations and financial commitments. Volatile and lower prices may also negatively impact our stock price.
The prices we receive for our oil, natural gas and natural gas 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 liquid has been volatile. For example, during the period from January 1, 2020 through December 31, 2022, the WTI 
spot price for oil 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 $9.85 per MMBtu in September 2022. During 2022, 
WTI spot prices ranged from $71.05 to $123.64 per Bbl and the Henry Hub spot price of natural gas ranged from $3.46 to $9.85 
per MMBtu. Likewise, natural gas liquids, which are made up of ethane, propane, isobutane, normal butane and natural 
gasoline, each of which have different uses and different pricing characteristics, have experienced significant declines in 
29

realized prices since the fall of 2014. The prices we receive for oil, natural gas and natural gas liquid we produce and our 
production levels depend on numerous factors beyond our control, including:
•
worldwide, regional and local economic and financial conditions impacting supply and demand;
•
the level of global exploration, development and production;
•
the level of global supplies, in particular due to supply growth from the United States;
•
the price and quantity of oil, natural gas and natural gas liquids imports to and exports from the U.S.;
•
political conditions in or affecting other oil, natural gas and natural gas liquid producing countries and 
regions, including the current conflicts in the Middle East, Asia and Eastern Europe;
•
the outbreak of military hostilities, including armed conflict between Russia and Ukraine and the potential 
destabilizing effect such conflict may pose for the European continent or the global oil and natural gas 
markets;
•
actions of the OPEC and state-controlled oil companies relating to production and price controls;
•
the extent to which U.S. shale producers become swing producers adding or subtracting to the world supply 
totals;
•
future regulations prohibiting or restricting our ability to apply hydraulic fracturing to our wells;
•
current and future regulations regarding well spacing;
•
prevailing prices and pricing differentials on local oil, natural gas and natural gas liquid price indices in the 
areas in which we operate;
•
localized and global supply and demand fundamentals and transportation, gathering and processing 
availability;
•
weather conditions;
•
technological advances affecting fuel economy, energy supply and energy consumption;
•
the effect of energy conservation measures, alternative fuel requirements and increasing demand for 
alternatives to oil and natural gas;
•
global or national health concerns, including health epidemics such as the COVID-19 pandemic at the 
beginning of 2020;
•
the price and availability of alternative fuels; and
•
domestic, local and foreign governmental regulation and taxes.
Lower oil, natural gas and natural gas liquid prices may reduce our cash flows and borrowing capacity. We may be unable to 
obtain needed capital or financing on satisfactory terms, which could lead to a decline in our hydrocarbon reserves as existing 
reserves are depleted. A decrease in prices could render development projects and producing properties uneconomic, potentially 
resulting in a loss of mineral leases. Low commodity prices have, at times, caused significant downward adjustments to our 
estimated proved reserves, and may cause us to make further downward adjustments in the future. Furthermore, our borrowing 
capacity could be significantly affected by decreased prices. A sustained decline in oil, natural gas and natural gas liquid prices 
could adversely impact our borrowing base in future borrowing base redeterminations, which could trigger repayment 
obligations under the Credit Agreement to the extent our outstanding borrowings exceed the redetermined borrowing base and 
could otherwise materially and adversely affect our future business, financial condition, results of operations, liquidity or ability 
to finance planned capital expenditures. In addition, lower oil, natural gas and natural gas liquid prices may typically cause a 
decline in the market price of our shares.
Low prices for oil, natural gas and natural gas liquids, could result in significant future write-downs of the financial 
carrying values of our properties in the future.
Accounting rules require that we periodically review the carrying value of our proved and unproved properties for possible 
impairment. Based on prevailing commodity prices and specific market factors and circumstances at the time of prospective 
impairment reviews, and the continuing evaluation of development plans, production data, economics and other factors, we may 
be required to significantly write-down the financial carrying value of our oil and natural gas properties, which constitutes a 
non-cash charge to earnings. We may incur impairment charges in the future, which could have a material adverse effect on our 
results of operations for the periods in which such charges are recorded.
A write-down could occur when oil and natural gas prices are low or if we have substantial downward adjustments to our 
estimated proved oil and natural gas reserves, if operating costs or development costs increase over prior estimates, or if 
exploratory drilling is unsuccessful.
The capitalized costs of our oil and natural gas properties, on a field-by-field basis, may exceed the estimated future net cash 
flows of that field. If so, we would record impairment charges to reduce the capitalized costs of such field to our estimate of the 
field’s fair market value. Unproved properties are evaluated at the lower of cost or fair market value. These types of charges 
will reduce our earnings and stockholders’ equity and could adversely affect our stock price.
30

We periodically assess our properties for impairment based on future estimates of proved and non-proved reserves, oil and 
natural gas prices, production rates and operating, development and reclamation costs based on operating budget forecasts. 
Once incurred, an impairment charge cannot be reversed at a later date even if price increases of oil and/or natural gas occur 
and in the event of increases in the quantity of our estimated proved reserves.
If oil, natural gas and natural gas liquid prices fall below current levels for an extended period of time and all other factors 
remain equal, we may incur impairment charges in the future. Such charges could have a material adverse effect on our results 
of operations for the periods in which they are recorded. See Note 8. Oil and Natural Gas Properties in the Notes to 
Consolidated Financial Statements included in this report for additional information.
Any significant reduction in our borrowing base under our Credit Agreement may negatively impact our liquidity and, 
consequently, our ability to fund our operations, including capital expenditures, and we may not have sufficient funds to 
repay borrowings under our Credit Agreement or any other obligation if required as a result of a borrowing base 
redetermination.
Availability under the Credit Agreement is subject to the lesser of elected commitments and the borrowing base then in effect.  
The borrowing base is subject to scheduled semiannual redeterminations (on or about May 1 and November 1), as well as other 
lender-elective borrowing base redeterminations. The lenders can unilaterally adjust the borrowing base, which impacts 
available borrowings permitted to be outstanding under the Credit 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 liquid reserves may result in a 
reduction in our borrowing base under the Credit Agreement (if prices are kept constant). Reductions in our borrowing base 
under the Credit Agreement could also arise from other factors, including but not limited to:
•
lower commodity prices or production;
•
increased leverage ratios;
•
inability to drill or unfavorable drilling results;
•
changes in oil, natural gas and natural gas liquid reserve engineering techniques;
•
increased operating and/or capital costs;
•
the lenders’ inability to agree to an adequate borrowing base; or
•
adverse changes in the lenders’ practices (including required regulatory changes) regarding estimation of 
reserves.
As of December 31, 2022, we had $520.1 million of borrowings outstanding out of the total $1.20 billion of elected 
commitments available under the Credit Agreement with a borrowing base of $1.85 billion. We may make further borrowings 
under the Credit Agreement in the future. Any significant reduction in our borrowing base below the elected commitments 
under the Credit Agreement as a result of borrowing base redeterminations or otherwise will negatively impact our liquidity and 
our ability to fund our operations and, as a result, could have a material adverse effect on our financial position, results of 
operations and cash flows. Further, if the outstanding borrowings under the Credit Agreement were to exceed the elected 
commitments as a result of any such redetermination, we could be required to repay the excess.
Our borrowings under our Credit Agreement expose us to interest rate risk. 
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.
Restrictive covenants in certain of our existing and future debt instruments may limit our ability to respond to changes in 
market conditions or pursue business opportunities.
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.
31

Our cost-mitigation initiatives and actions may not offset, largely or at all, the impacts of inflationary pressures on our 
operating costs and capital expenditures.
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. 
Unless we replace our reserves, our production and estimated reserves will decline, which may adversely affect our financial 
condition, results of operations and/or cash flows.
Producing oil and natural gas reservoirs are generally characterized by declining production rates that may vary depending upon 
reservoir characteristics and other factors. Decline rates are typically greatest early in the productive life of a well, particularly 
horizontal wells. Estimates of the decline rate of an oil or natural gas well are inherently imprecise and may be less precise with 
respect to new or emerging oil and natural gas formations with limited production histories than for more developed formations 
with established production histories. Our production levels and the reserves that we currently expect to recover from our wells 
will change if production from our existing wells declines in a different manner than we have estimated and can change under 
other circumstances. Thus, our estimated future oil and natural gas reserves and production and, therefore, our cash flows and 
results of operations are highly dependent upon our success in efficiently developing and exploiting our current properties and 
economically finding or acquiring additional recoverable reserves. We may not be able to develop, find or acquire additional 
reserves to replace our current and future production at acceptable costs. If we are unable to replace our current and future 
production, our cash flows and the value of our reserves may decrease, adversely affecting our business, financial condition and 
results of operations.
Estimates of proved oil and natural gas reserves involve assumptions and any material inaccuracies in these assumptions 
will materially affect the quantities and the value of those reserves.
This report contains estimates of our proved oil and natural gas reserves. These estimates are based upon various assumptions, 
including assumptions required by SEC regulations relating to oil and natural gas prices, drilling and operating expenses, 
capital expenditures, taxes and availability of funds. The process of estimating oil and natural gas reserves is complex and 
requires significant decisions, complex analyses and assumptions in evaluating available geological, geophysical, engineering 
and economic data for each reservoir. Therefore, these estimates are inherently imprecise.
Our actual future production, oil and natural gas prices, revenues, taxes, development expenditures, operating expenses and 
quantities of recoverable oil and natural gas reserves will vary from those estimated. Any significant variance will likely 
materially affect the estimated quantities and the estimated value of our reserves. In addition, we may later adjust estimates of 
proved reserves to reflect production history, results of exploration and development activities, prevailing oil and natural gas 
prices and other factors, many of which are beyond our control.
Quantities of estimated proved reserves are based on economic conditions in existence during the period of assessment. 
Changes to oil, natural gas and natural gas 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.
Negative revisions in the estimated quantities of proved reserves have the effect of increasing the rates of depletion on the 
affected properties, which decrease earnings or result in losses through higher depletion expense. These revisions, as well as 
revisions in the assumptions of future estimated cash flows of those reserves, may also trigger impairment losses on certain 
properties, which may result in non-cash charges to earnings. See Note 8. Oil and Natural Gas Properties in the Notes to 
Consolidated Financial Statements included in this report.
The development of our estimated proved undeveloped reserves may take longer and may require higher levels of capital 
expenditures than we currently anticipate. Therefore, our estimated proved undeveloped reserves may not be ultimately 
developed or produced.
At December 31, 2022, approximately 28% of our estimated proved reserves were classified as proved undeveloped. The 
development of our estimated proved undeveloped reserves of 103,215 MBoe will require an estimated $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 
32

on successful drilling and completion results, future commodity prices, costs and economic assumptions that align with our 
internal forecasts, as well as access to liquidity sources, such as the capital markets, the Credit Agreement and derivative 
contracts. Delays in the development of our reserves, increases in costs to drill and develop such reserves, or decreases in 
commodity prices will reduce the PV-10 value of our estimated proved undeveloped reserves and future net revenues estimated 
for such reserves and may result in some projects becoming uneconomic. Moreover, under the 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. 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 the actual capital expenditures may vary from estimated 
capital expenditures, development may not occur as scheduled and actual results may be less than estimated.
The standardized measure of discounted future net cash flows from our estimated proved reserves may not be the same as 
the current market value of our estimated oil and natural gas reserves.
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, 2022, 2021 and 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 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 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 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 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.
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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 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. 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 2023 capital expenditures with cash 
on hand, cash generated by operations, borrowings under the Credit Agreement and possibly through additional capital market 
transactions. The actual amount and timing of our future capital expenditures may differ materially from our estimates as a 
result of, among other things, oil and natural gas prices, actual drilling results, the availability of high-quality drilling rigs and 
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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 Credit Agreement.
If our revenues or the borrowing base under the Credit Agreement decrease as a result of low oil and natural gas prices, 
operating difficulties, declines in reserves or for any other reason, we may have limited ability to obtain the capital necessary to 
sustain our operations and growth at current levels. If additional capital is needed, we may not be able to obtain debt or equity 
financing on terms acceptable to us, if at all. The failure to obtain additional financing could result in a curtailment of our 
operations relating to development of our properties, which in turn could lead to a decline in our reserves and production and 
would adversely affect our business, financial condition and results of operations.
A negative shift in 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 and 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, which may result 
35

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, 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 Discussion and Analysis of 
Financial Condition and Results of Operations and Note 7. Derivative Financial Instruments in the Notes to Consolidated 
Financial Statements included in this report.
The oil and natural gas industry is highly competitive, and our size may put us at a disadvantage in competing for resources.
The oil and natural gas industry is highly 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 somewhat dependent on our ability to acquire and develop mineral leases and oil and gas properties with 
economically recoverable oil and natural gas reserves. Acquiring additional oil and natural gas properties, or businesses that 
own or operate such properties is presently a component of our business strategy. However, 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 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 
37

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 SDWA to require federal permitting of 
hydraulic fracturing and the disclosure of chemicals used in the hydraulic fracturing process. 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 the 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 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 this notice, any action that temporarily or permanently restricts the availability of disposal capacity for 
produced water or other fluids may increase our costs or 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 exploitation and development activities and equipment could be adversely affected by extreme weather conditions, such as 
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.
Our operations are subject to a series of risks arising out of the threat of climate change that could result in increased 
operating costs, limit the areas in which we may conduct oil, natural gas and natural gas liquid exploration and production 
activities, and reduce demand for the oil, natural gas and natural gas liquid we produce.
In the United States, no comprehensive climate change legislation has been implemented at the federal level. However, 
President Biden has highlighted addressing climate change as a priority of 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 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 of GHG emissions from specified 
onshore and offshore oil and 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 has been subject to substantial uncertainty in recent years. In June 
2016, the EPA finalized NSPS, known as Subpart OOOOa, that establish emission standards for methane and VOCs from new 
and modified oil and natural gas production and natural gas processing and transmission facilities. In September 2020, the EPA 
finalized amendments to the 2016 standards that removed the transmission and storage segment from the oil and natural gas 
source category and rescinded the methane-specific requirements for production and processing facilities. However, President 
Biden signed an executive order on his first day in office calling for the suspension, revision, or rescission of the September 
2020 rule and the reinstatement or issuance of methane emission standards for new, modified and existing oil and gas facilities.  
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 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 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 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 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 
39

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 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 
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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 increased 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 develop and produce our 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 are primarily sold in 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 lifting of prior restrictions on the exporting of oil and natural gas.
Changes in tax laws or the interpretation thereof or the imposition of new or increased taxes or fees may adversely affect 
our operations and cash flows.
From time to time, federal and state level legislation has been proposed that would, if enacted into law, make significant 
changes to tax laws, including to certain key federal and state income tax provisions currently available to oil and natural gas 
exploration and development companies. Such legislative changes have included, but have not been limited to, (i) the 
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) an extension of the amortization period for certain geological and 
geophysical expenditures, (iv) the elimination of certain other tax deductions and relief previously available to oil and natural 
gas companies and (v) an increase in the federal income tax rate applicable to corporations such as us. It is unclear whether 
these or similar changes will be enacted and, if enacted, how soon any such changes could take effect. Additionally, states in 
which we operate or own assets may impose new or increased taxes or fees on oil and natural gas extraction. The passage of 
any legislation as a result of these proposals and other similar changes in federal income tax laws or the imposition of new or 
increased taxes or fees on oil and natural gas extraction could adversely affect our operations and cash flows.
In addition, on August 16, 2022, President Biden signed into law the IRA, which includes, among other things, a corporate 
alternative minimum tax (the "CAMT"), provides for an investment tax credit for qualified biomass property and introduces a 
one percent excise tax on corporate stock repurchases after December 31, 2022. Under the CAMT, a 15 percent minimum tax 
will be imposed on certain 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 and affiliates for a three-
taxable-year period ending prior to such taxable year exceeds $1 billion. We are currently assessing the potential impact of 
these legislative changes and will continue to evaluate the overall impact of other current, future and proposed regulations and 
interpretive guidance from tax authorities on our effective tax rate and consolidated balance sheets. We are unable to predict 
whether any such changes or other proposals will ultimately be enacted.
Our operations are substantially dependent on the availability, use and disposal of water. New legislation and regulatory 
initiatives or restrictions relating to water disposal wells could have a material adverse effect on our future business, 
financial condition, operating results and prospects.
Water is an essential component of our drilling and hydraulic fracturing processes. If we are unable to obtain water to use in our 
operations from local sources, we may be unable to economically produce oil, natural gas and natural gas liquids, which could 
have an adverse effect on our business, financial condition and results of operations. Wastewaters from our operations typically 
are disposed of via underground injection. Some studies have linked earthquakes in certain areas to underground injection, 
which is leading to greater public scrutiny of disposal wells. Any new environmental initiatives or regulations that restrict 
injection of fluids, including, but not limited to, produced water, drilling fluids and other wastes associated with the exploration, 
development or production of oil and gas, or that limit the withdrawal, storage or use of surface water or ground water 
necessary for hydraulic fracturing of our wells, could increase our operating costs and cause delays, interruptions or cessation of 
our operations, the extent of which cannot be predicted, and all of which would have an adverse effect on our business, 
financial condition, results of operations and cash flows.
41

Any change to government regulation or administrative practices may have a negative impact on our ability to operate and 
our profitability.
Oil and natural gas operations are subject to substantial regulation under federal, state and local laws relating to the exploration 
for, and the development, upgrading, marketing, pricing, taxation, and transportation of, oil and natural gas and related products 
and other associated matters. Amendments to current laws and regulations governing operations and activities of oil and natural 
gas exploration and development operations could have a material adverse impact on our business. In addition, there can be no 
assurance that income tax laws, royalty regulations and government programs related to our oil and natural gas properties and 
the oil and natural gas industry generally will not be changed in a manner which may adversely affect our progress or cause 
delays.
Permits, leases, licenses, and approvals are required from a variety of regulatory authorities at various stages of exploration and 
development. There can be no assurance that the various government permits, leases, licenses and approvals sought will be 
granted in respect of our activities or, if granted, will not be cancelled or will be renewed upon expiration. There is no assurance 
that such permits, leases, licenses, and approvals will not contain terms and provisions which may adversely affect our 
exploration and development activities.
The current presidential administration, acting through the executive branch and/or in coordination with Congress, already 
has ordered or proposed, and could enact additional rules and regulations that restrict our ability to acquire federal leases in 
the future.
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 production is dependent upon gathering systems, transportation facilities and processing facilities 
that we do not own or control. If these facilities or systems are unavailable, or if we are unable to access these facilities on 
commercially reasonable terms, our oil and natural gas production can be interrupted and our revenues reduced.
The marketability of our oil and natural gas production is dependent upon the availability, proximity and capacity of pipelines, 
natural gas gathering systems, transportation and processing facilities owned by third parties. In general, we will not control 
these facilities, and our access to them may be limited or denied due to circumstances beyond our control. A significant 
disruption in the availability 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. These are risks for which we generally will not maintain insurance.
New climate disclosure rules proposed by the SEC may increase our costs of compliance and adversely impact our business.
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.
We operate or participate in oil and natural gas leases with third parties who may not be able to fulfill their commitments to 
our projects.
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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. In 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 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.
Use of debt financing may adversely affect our strategy and financial viability.
We may 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.
Our business could be materially and adversely affected by security threats, including cybersecurity threats, and other 
disruptions.
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 could have a material and adverse effect on our 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 externally hosted hardware and 
software platforms, to (i) estimate our oil and gas 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 and vendors, suppliers and other 
third parties. Further, our reliance on technology has increased 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 
implemented and invested in, and will continue to implement and invest in, controls, procedures and protections (including 
internal and external personnel) that are designed to protect our systems, identify and remediate on a regular basis 
vulnerabilities in our systems and related infrastructure and monitor and mitigate the risk of data loss and other cybersecurity 
threats, such measures cannot entirely eliminate cybersecurity threats and the controls, procedures and protections we have 
implemented and invested in may prove to be ineffective.
Our systems and networks, and those of our business associates, may become the target of cybersecurity attacks, including, 
without limitation, denial-of-service attacks; malicious software; data privacy breaches by employees, insiders or 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 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:
•
unauthorized access to, and release of, our business data, reserves information, strategic information or other 
sensitive or proprietary information, which could have a material and adverse effect on our ability to compete 
for oil and natural gas resources, or reduce our competitive advantage over other companies;
•
data corruption, communication interruption, or other operational disruptions during our drilling activities, 
which could result in our failure to reach the intended target or a drilling incident;
•
data corruption or operational disruptions of our production-related infrastructure, which could result in loss 
of production or accidental discharges;
•
unauthorized access to, and release of, personal information of our royalty owners, employees and vendors, 
which could expose us to allegations that we did not sufficiently protect such information;
•
a cybersecurity attack on a vendor or service provider, such as a national or regional power grid, which could 
result in supply chain or other disruptions and could delay or halt our operations;
•
a cybersecurity attack on third-party gathering, transportation, processing, fractionation, refining or export 
facilities, which could result in reduced demand for our production or delay or prevent us from transporting 
and marketing our production, in either case resulting in a loss of revenues;
43

•
a cybersecurity attack involving commodities exchanges or financial institutions could slow or halt 
commodities trading, thus preventing us from marketing our production or engaging in hedging activities, 
resulting in a loss of revenues;
•
a deliberate corruption of our financial or operating data could result in events of non-compliance which 
could then lead to regulatory fines or penalties;
•
a cybersecurity attack on a communications network or power grid, which could cause operational disruptions 
resulting in a loss of revenues; and
•
a cybersecurity attack on our automated and surveillance systems, which could cause a loss of production and 
potential environmental hazards.
Further, strategic targets, such as energy-related assets, may be at a greater risk of terrorist attacks or cybersecurity attacks than 
other targets in the United States. Moreover, external digital technologies control nearly all of the crude oil and natural gas 
distribution and refining systems in the U.S. and abroad, which are necessary to transport and 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 environment; (ii) disrupt energy supplies and markets, by delaying or preventing 
delivery of production to markets; and (iii) make it difficult or impossible to accurately account for production and settle 
transactions.
Any such terrorist attack or cybersecurity attack that affects us, our customers, suppliers, or others with whom we do business 
and/or energy-related assets could have a material adverse effect on our business, including disruption of our operations, 
damage to our reputation, a loss of 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 our systems and 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 avoiding disruption and 
business impacts. Further, our insurance may not be adequate to compensate us for all resulting losses, and the 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 have implemented and invested in, and will continue to implement and invest in, controls, procedures and protections 
(including internal and external personnel) that are designed to protect our systems, identify and remediate on a regular basis 
vulnerabilities in our systems and related infrastructure and monitor and mitigate the risk of data loss and other cybersecurity 
threat. Such measures, however, cannot entirely eliminate cybersecurity threats and the controls, procedures and protections we 
have implemented and invested in may prove to be ineffective. We maintain specialized insurance for possible liability 
resulting from a cyberattack on our assets, however, we cannot assure you that the insurance coverage will be adequate to cover 
claims that may arise, or that we will be able to maintain adequate insurance at rates we consider reasonable. A loss not fully 
covered by insurance could have a material adverse effect on our financial position, results of operations and cash flows.
The loss or unavailability of any of our executive officers or other key employees could have a material adverse effect on our 
business.
We depend greatly on the efforts of our executive officers and other key employees to manage our operations. The loss or 
unavailability of any of our executive officers or other key employees could have a material adverse effect on our business.
We may be involved in, or our assets may be affected by, legal and regulatory proceedings that could result in substantial 
liabilities.
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.
Risks Related to the Ownership of our Class A Common Stock
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We are a holding company and the sole manager of EEH. Our only material asset is our equity interest in EEH and, 
accordingly, we are dependent upon distributions from EEH to cover our corporate and other overhead expenses and pay 
taxes.
We are a holding company and the sole manager of EEH. We have no material assets other than our equity interest in EEH. We 
have no independent means of generating revenue. We expect EEH to reimburse us for our corporate and other overhead 
expenses, and to the extent EEH has available cash, we intend to cause EEH to make distributions to the holders of EEH Units, 
including us, as 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 need funds, and EEH or its subsidiaries are 
restricted from making such distributions under applicable law or regulation or under the terms of their financing arrangements, 
or are otherwise unable to provide such funds, it could materially adversely affect our liquidity and financial condition.
Our principal stockholders hold substantial voting power of our Class A Common Stock and Class B Common Stock.
Holders of Class A Common Stock and our Class B Common Stock 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 Earthstone's Third Amended 
and Restated Certificate of Incorporation, as amended (the “Certificate of Incorporation”). As of December 31, 2022, EnCap, 
affiliates of Post Oak and affiliates of Warburg beneficially own approximately 40.1%, 7.9% and 9.2%, respectively, of our 
voting interests and, along with their affiliates, could limit the ability of our other stockholders to approve transactions they may 
deem to be in the best interests of our Company or delaying or preventing changes in control or changes in our management.
As long as EnCap and certain of its affiliates, affiliates of Post Oak, and affiliates of Warburg continue to control a significant 
amount of our outstanding voting securities, they will have the authority to exercise significant influence over management and 
all matters requiring stockholder approval, regardless of whether or not other stockholders believe that a potential transaction is 
in their own best interests. Also, in any of these matters, the interests of our management team may differ or conflict with the 
interests of our stockholders. In addition, EnCap and its affiliates, 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 significant percentage of our voting securities.
Bold Holdings (controlled by EnCap) and its permitted transferees have the right to exchange their EEH Units and shares 
of Class B Common Stock for our Class A Common Stock pursuant to the terms of the EEH LLC Agreement.
As of March 1, 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. 
Future sales of our Class A Common Stock in the public market, or the perception that such sales may occur, could reduce 
our stock price, and any additional capital raised by us through the sale of equity may dilute your ownership in us.
We may sell additional shares of Class A Common Stock or securities convertible into shares of our Class A Common Stock in 
subsequent offerings. Additionally, 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.
We have no current plans to pay dividends on our Class A Common Stock. Stockholders may not receive funds without 
selling their shares.
We do not anticipate paying any cash dividends on our Class A Common Stock in the foreseeable future. We currently intend to 
retain future earnings, if any, to finance the expansion of our business. In addition, the Credit Agreement and the Indenture limit 
EEH’s ability to make any significant payments to us.
45

Our Board of Directors can, without stockholder approval, cause preferred stock to be issued on terms that could adversely 
affect our common stockholders.
Under the Certificate of Incorporation, our Board is authorized to cause Earthstone to issue up to 20,000,000 shares of preferred 
stock, of which none are issued and outstanding as of the date of this report. Also, our Board, without stockholder approval, 
may determine the price, rights, preferences, privileges, and restrictions, including voting rights, of those shares. If the Board 
causes shares of preferred stock to be issued, the rights of the holders of our Class A Common Stock and Class B Common 
Stock would likely be subordinate to those of preferred holders and therefore could be adversely affected. The Board’s ability to 
determine the terms of preferred stock and to cause its issuance, while providing desirable flexibility in connection with 
possible acquisitions and other corporate purposes, could have the effect of making it more difficult for a third-party to acquire 
a majority of our outstanding voting stock or otherwise seek to acquire us. Shares of preferred stock issued by us could include 
voting rights, or even super voting rights, which could shift the ability to control Earthstone to the holders of the preferred 
stock. Preferred stock could also have conversion rights into shares of Class A Common Stock at a discount to the market price 
of the Class A Common Stock which could negatively affect the market for our Class A Common Stock. In addition, preferred 
stock could have preference in the event of liquidation of Earthstone, which means that the holders of preferred stock would be 
entitled to receive the net assets of Earthstone distributed in liquidation before the Class A common stockholders receive any 
distribution of the liquidated assets.
The price of our Class A Common Stock may fluctuate significantly, which could negatively affect us and holders of our 
Class A Common 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. Adverse events including 
changes in production volumes, worldwide demand and prices for crude oil and natural gas, regulatory developments, and 
changes in securities analysts’ estimates of our financial performance could negatively impact the market price of our Class A 
Common Stock. General market conditions, including the level of, and fluctuations in, the trading prices of stocks generally 
could also have a similar negative impact. The stock markets regularly experience price and volume volatility that affects many 
companies’ stock prices without regard to the operating performance of those companies. Volatility of this type may affect the 
trading price of our Class A Common Stock.
Anti-takeover provisions could make a third-party acquisition difficult.
The Certificate of Incorporation provides for a classified board of directors, with each member serving a three-year term. 
Provisions in the Certificate of Incorporation could make it more difficult for a third-party to acquire us without the approval of 
our Board. In addition, the Delaware corporate statutes also contain certain provisions that could make an acquisition by a third-
party more difficult.
Our stockholders may act by unilateral written consent.
Under 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.
Item 1B. Unresolved Staff Comments
None.
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Item 2. Properties
Summary of Oil and Gas Properties 
Midland Basin
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. 
Delaware Basin
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.
Eagle Ford Trend
As of December 31, 2022, we had approximately 3,000 net leasehold acres in the Eagle Ford Trend, primarily in the crude oil 
window in Gonzales and Karnes counties which include 33 gross / 30 net operated producing wells.
Oil and Natural Gas Reserves
As of December 31, 2022, all of our oil, natural gas and natural gas liquids reserves are located in New Mexico and Texas. We 
expect to further develop these properties through additional drilling and completion operations. Our reserve estimates have 
been prepared by Cawley, Gillespie & Associates, Inc. (“CG&A”), an independent petroleum engineering firm. The scope and 
results of CG&A’s procedures are summarized in a letter which is included as an exhibit to this report. For further information 
on estimated reserves, including information on estimated future net cash flows and the standardized measure of discounted 
future net cash flows, please refer to the Note 20. Supplemental Information On Oil and Gas Exploration and Production 
Activities (Unaudited) in Part II, Item 8 of the Notes to Consolidated Financial Statements of this report.
As of December 31, 2022, our estimated proved reserves totaled 367,936 MBoe and had a PV-10 value of approximately $7.8 
billion (reconciled in “Non-GAAP Measures” below) and a Standardized Measure of Discounted Future Net Cash Flows of 
approximately $6.7 billion, all of which relate to our properties in New Mexico and Texas. During 2022, we incurred 
approximately $530.6 million in capital expenditures, primarily drilling and completion costs. We expect to further develop our 
properties through additional drilling. 
2022 Activity in Proved Reserves
From January 1, 2022 to December 31, 2022, our total estimated proved reserves increased 149% from 147,587 MBoe to 
367,936 MBoe. Of that, estimated proved developed reserves increased 183% from 93,575 MBoe to 264,721 MBoe and 
estimated proved undeveloped reserves increased 91% from 54,012 MBoe to 103,215 MBoe. The most significant increase in 
our total estimated proved reserves resulted from purchases of minerals in place resulting from the Chisholm Acquisition, 
Bighorn Acquisition and Titus Acquisition, all completed in 2022.
47

Proved Reserves as of December 31, 2022
The below table sets forth a summary of our estimated crude oil, natural gas and natural gas liquid reserves as of December 31, 
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, 2022. The prices used in estimating proved reserves are based on the unweighted arithmetic average 
of the first-day-of-the-month price for each month within the 12-month period for the year. All prices and costs associated with 
operating wells were held constant in accordance with the SEC guidelines.
Our proved reserve categories as of December 31, 2022 are summarized in the table below:
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 
(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)
$ 
7,789,619 
Future income taxes, discounted at 10%
 
(1,065,118) 
Standardized measure of discounted future net cash flows (2)
$ 
6,724,501 
(1)
Includes $1.9 billion attributable to noncontrolling interests.
(2)
Includes $1.6 billion attributable to noncontrolling interests.
Reserve Quantity Information
The following table illustrates our estimated net proved reserves, including changes, and proved developed and proved 
undeveloped reserves for the periods indicated. The oil price as of December 31, 2022 is based on the respective 12-month 
unweighted average of the first of the month prices of the WTI spot prices which equates to $93.67 per barrel. The natural gas 
price as of December 31, 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 $6.36 per MMBtu. The natural gas liquid price used to value reserves as of December 
48

31, 2022 averaged $39.24 per barrel. All prices are adjusted by lease or field for energy content, transportation fees, and market 
differentials, resulting in the aforementioned oil, natural gas and natural gas 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.
A summary of our changes in quantities of proved oil, natural gas and natural gas liquid reserves for the year ended December 
31, 2022 are as follows:
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 
The table below presents the quantities of proved oil, natural gas and natural gas liquid reserves attributable to noncontrolling 
interests as of December 31, 2022:
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 
Notable changes in proved reserves for the year ended December 31, 2022 included the following:
•
Extensions. In 2022, extensions of 29.9 MMBoe were primarily the result of successful drilling results in the 
Midland Basin.
•
Purchases of minerals in place. In 2022, we completed multiple acquisitions that resulted in 213.1 MMBoe in 
additional reserves, as disclosed in Note 4. Acquisitions and Divestitures in the Notes to Consolidated 
Financial Statements.
•
Revision to previous estimates. In 2022, the upward revisions of prior reserves of 10.5 MMBoe consisted of 
6.5 MMBoe related to changes in price and 4.0 MMBoe related to changes in performance and other 
economic factors.
Proved Undeveloped Reserves
Proved undeveloped reserves (“PUDs”) increased from 54,012 MBoe to 103,215 MBoe or 91%, as of December 31, 2022 
compared to December 31, 2021. PUDs represent 28% of our total proved reserves. Certain previously booked PUDs were 
reclassified as proved developed reserves due to successful drilling efforts. In accordance with our December 31, 2022 year-end 
independent engineering reserve report, we plan to drill all of our individual PUD drilling locations within the five years of 
original classification.
49

Changes in our PUD reserves for the year ended December 31, 2022 were as follows (in MBoe):
Proved undeveloped reserves at December 31, 2021 (1)
 
54,012 
Conversions to developed
 
(22,637) 
Extensions
 
16,499 
Purchases of minerals in place
 
57,432 
Revision to previous estimates
 
(2,091) 
Proved undeveloped reserves at December 31, 2022 (2)
 
103,215 
(1)
Includes 21,125 MBoe attributable to noncontrolling interests.
(2)
Includes 25,293 MBoe attributable to noncontrolling interests.
2022 Changes in Proved Undeveloped Reserves
Conversions to developed. In our year-end 2021 plan to develop our PUDs within five years, it was estimated that 
$190.2 million of capital would be expended in 2022 for the conversion of 45 gross / 31.8 net PUDs to add 24.5 MMBoe. In 
2022, we spent $191.2 million to convert 42 gross / 26.6 net PUDs adding 22.6 MMBoe to developed.
Extensions. In 2022, extensions of 16.5 MMBoe were primarily the result of successful drilling results in the Delaware Basin 
and the Midland Basin.
Purchases of minerals in place. In 2022, we completed multiple acquisitions that resulted in 57.4 MMBoe of additional 
reserves, as disclosed in Note 4. Acquisitions and Divestitures in the Notes to Consolidated Financial Statements.
Revision to previous estimates. Downward revisions of prior reserves of 2.1 MMBoe consisted of 2.4 MMBoe related to 
changes in performance and other economic factors, offset by a positive revision of 0.3 MMBoe related to changes in prices.
Estimated Costs Related to Conversion of Proved Undeveloped Reserves to Proved Developed Reserves
 
The following table sets forth the estimated timing and cash flows of developing our proved undeveloped reserves at December 
31, 2022 ($ in thousands):
Years Ended December 31, (1)
Future 
Production 
(MBoe) (2)
Future Cash 
Inflows (3)
Future 
Production 
Costs
Future 
Development 
Costs
Future Net 
Cash Flows
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 
(1)
Beginning in 2023 and thereafter, the production and cash flows represent the drilling results from the 
respective year plus the incremental effects from the results of proved undeveloped drilling from previous 
years. These production volumes, inflows, expenses, development costs and cash flows are limited to the 
PUD reserves and do not include any production or cash flows from the Proved Developed category which 
will also help to fund our capital program.
(2)
Barrels of oil equivalent have been calculated on the basis of six thousand cubic feet (Mcf) of natural gas 
equal to one barrel of oil equivalent (Boe).
(3)
Computation is based on SEC pricing of (i) $95.82 per Bbl (WTI-Cushing oil spot prices, adjusted for 
differentials), (ii) $5.51 per Mcf (Henry Hub spot natural gas price), as adjusted for location and quality by 
property, and (iii) $39.24 per Bbl for natural gas liquids.
PUD reserves are expected to be recovered from new wells on undrilled acreage or from existing wells where additional capital 
expenditures are required, such as from drilled but uncompleted ("DUC") wells. Our development plan contemplates production 
to commence from all these wells by 2026.
Historically, our drilling programs have been substantially funded from our cash flow and borrowings under our Credit 
Agreement. Based on current commodity prices and our current expectations over the next five years of our cash flows and 
50

drilling programs, which includes drilling of proved undeveloped and unproven locations, we believe that we can continue to 
substantially fund our drilling activities from our cash flow and with borrowings under the Credit Agreement. 
Preparation of Reserve Estimates
We engaged an independent petroleum engineering consulting firm, CG&A, to prepare our annual reserve estimates and we 
have relied on CG&A’s expertise to ensure that our reserve estimates are prepared in compliance with SEC guidelines.
The technical person primarily responsible for the preparation of the reserve report is W. Todd Brooker, President of CG&A. 
He graduated with honors from the University of Texas at Austin in 1989 with a Bachelor of Science degree in Petroleum 
Engineering. Mr. Brooker is a Registered Professional Engineer in the State of Texas (License No. 83462) and has more than 
25 years of experience in the estimation and evaluation of oil and natural gas reserves. He is also a member of the Society of 
Petroleum Engineers.
Geoffrey A. Vernon, our Vice President of Reservoir Engineering and A&D, is responsible for reservoir engineering, is a 
qualified reserve estimator and auditor and is primarily responsible for overseeing CG&A during the preparation of our annual 
reserve estimates. His professional qualifications meet or exceed the qualifications of reserve estimators and auditors set forth 
in the “Standards Pertaining to Estimation and Auditing of Oil and Natural Gas Reserves Information” promulgated by the 
Society of Petroleum Engineers. His qualifications include a Bachelor of Science degree in Chemical Engineering from Texas 
Tech University in 2007; a Master of Business Administration degree from Rice University in 2014; member of the Society of 
Petroleum Engineers since 2007; and more than 15 years of practical experience in estimating and evaluating reserve 
information with more than 10 of those years being in charge of estimating and evaluating reserves.
We maintain adequate and effective internal controls over our reserve estimation process as well as the underlying data upon 
which reserve estimates are based. The primary inputs to the reserve estimation process are technical information, financial 
data, ownership interest and production data. The relevant field and reservoir technical information, which is updated, at least, 
annually, is assessed for validity when CG&A has technical meetings with our engineers, geologists, operations and land 
personnel. Current revenue and expense information is obtained from our accounting records, which are subject to external 
quarterly reviews, annual audits and our own set of internal controls over financial reporting. Internal controls over financial 
reporting are assessed for effectiveness annually using criteria set forth in Internal Control – Integrated Framework, (2013 
Version) issued by the Committee of Sponsoring Organizations of the Treadway Commission. All current financial data such as 
commodity prices, lease operating expenses, production taxes and field level commodity price differentials are updated in the 
reserve database and then analyzed to ensure that they have been entered accurately and that all updates are complete. Our 
current ownership in mineral interests and well production data are also subject to our internal controls, and they are 
incorporated in our reserve database as well and verified internally by our personnel to ensure their accuracy and completeness. 
Once the reserve database has been updated with current information, and the relevant technical support material has been 
assembled, CG&A meets with our technical personnel to review field performance and future development plans in order to 
further verify the validity of estimates. Following these reviews, the reserve database is furnished to CG&A so that it can 
prepare its independent reserve estimates and final report. The reserve estimates prepared by CG&A are reviewed and 
compared to our internal estimates by Mr. Vernon, our Vice President of Reservoir Engineering and A&D. Material reserve 
estimation differences are reviewed between CG&A and us, and additional data is provided to address the differences. If the 
supporting documentation will not justify additional changes, the CG&A reserves are accepted. In the event that additional data 
supports a reserve estimation adjustment, CG&A will analyze the additional data, and may make changes it solely deems 
necessary. Additional data is usually comprised of updated production information on new wells. Once the review is completed 
and all material differences are reconciled, the reserve report is finalized and our reserve database is updated with the final 
estimates provided by CG&A.
51

Net Oil, Natural Gas and Natural Gas Liquid Production, Average Price and Average Production Cost
The consolidated net quantities of oil, natural gas and natural gas liquids produced and sold by us for the years ended December 
31, 2022, 2021 and 2020, the average sales price per unit sold (excluding hedges) and the average production cost per unit are 
presented below:
 
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 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, 2022, 2021 and 2020.
Midland Basin
 
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 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.
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 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.
53

Eagle Ford Trend
 
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 
* 
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, 2022. A net 
well represents our percentage of ownership of a gross well.
 
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 area as of December 31, 2022. Net 
acreage represents our percentage ownership of gross acreage.
 
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, 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
 
2023
2024
2025
Total
 
Gross
Net
Gross
Net
Gross
Net
Gross
Net
Midland Basin
 
—  
—  
442  
442  
791  
791  
1,233  
1,233 
Delaware Basin
 
393  
393  
320  
320  
280  
280  
993  
993 
Eagle Ford Trend
 
—  
—  
—  
—  
—  
—  
—  
— 
Total
 
393  
393  
762  
762  
1,071  
1,071  
2,226  
2,226 
Approximately 99% of the Midland Basin 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 (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 (15.3 net) that were drilled and uncompleted or in the 
process of 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.
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, 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 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
Shares of our Class A Common Stock are listed on the NYSE under the symbol “ESTE.” 
Holders
As of March 1, 2023, there were approximately 1,800 holders of record of our Class A Common Stock and 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 and do not have any current plans to pay a dividend. 
Furthermore, the Credit Agreement 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
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, 2017 through December 31, 2022, relative to the cumulative total returns of the 
S&P 500 Index, the E&P Index and the XOP. The graph assumes the investment of $100 on December 31, 2017 in our Class A 
Common Stock and each index and the reinvestment of all dividends, if any.
56

Item 6. Reserved
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, asset and corporate acquisitions 
and mergers. Our operations are all in the upstream segment of the oil and natural gas industry and all our properties are 
onshore in the United States. Our primary assets are located in the Midland Basin in West Texas and the 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 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 in West Texas and the Delaware Basin in New Mexico, both containing 
high oil and liquids rich resources which provides us with multiple horizontal targets with proven production results, long-lived 
reserves and historically high drilling success rates.
Consolidation Focus
We continue to pursue value-accretive and scale-enhancing consolidation opportunities, as we believe we are in a position to 
operate effectively despite the volatility in commodity prices. We are focusing our attention on acquisition and corporate 
merger 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 close proximity to our existing acreage that would allow for longer 
horizontal laterals providing higher economic returns, increased operated inventory and greater operating efficiency. In short, 
we believe we are well qualified to continue to be a consolidator which could increase the scale of our operations and add value 
to our shareholders.
Midland Basin
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. 
Delaware Basin
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.
58

Results of Operations 
Year ended December 31, 2022 compared to the year ended December 31, 2021 
 
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 %
 
(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, 2022, oil revenues increased by $817.2 million or 275% compared to 2021. Of the increase, 
$702.9 million was attributable to an increase in volume and $114.3 million was attributable to an increase in our realized price. 
Our average realized price per Bbl increased from $67.83 for the year ended December 31, 2021 to $93.91 or 38% for the year 
ended December 31, 2022. We had a net increase in the volume of oil sold of 7,485 MBbls or 171%, which included an 
increase of 7,136 MBbls related to the wells acquired in the 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, 2022, natural gas revenues increased by $253.0 million or 498% compared to 2021. Of the 
increase, $222.8 million was due to increased sales volumes and $30.2 million was attributable to an increase in realized price. 
Our average realized price per Mcf increased 60% from $3.50 for the year ended December 31, 2021 to $5.59 for the year 
ended December 31, 2022. The total volume of natural gas produced and sold increased 39,886 MMcf or 275% which included 
an increase of 39,666 MMcf related to the wells acquired in the Acquisitions, partially offset by a decrease of 220 MMcf in our 
other wells primarily resulting from natural production declines.
Natural gas liquid revenues
For the year ended December 31, 2022, natural gas liquid revenues increased by $205.3 million or 287% compared to 2021. Of 
the increase, $194.7 million was attributable to higher sales volumes and $10.6 million was due to an increase in our realized 
price. The volume of natural gas liquids produced and sold increased by 5,343 MBbls or 237%, primarily resulting from an 
increase of 5,308 MBbls related to the wells acquired in the 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 gathering, processing and transportation costs, insurance expenses and overhead 
charges provided for in operating agreements.
LOE increased by $181.2 million or 367% for the year ended December 31, 2022 compared to 2021, primarily due to a $158.2 
million increase resulting from the LOE of the properties acquired in the Acquisitions and a $20.8 million increase resulting 
from new wells brought online as a result of our 2022 drilling program and increased costs due to inflation in 2022.
Production and ad valorem taxes
Production and ad valorem taxes for the year ended December 31, 2022 increased by $96.6 million or 366% compared to 2021, 
due to an $84.7 million increase resulting from the properties acquired in the Acquisitions and an $11.9 million increase related 
to our other wells resulting from higher commodity prices.
Depreciation, depletion and amortization (“DD&A”)
 
DD&A increased for the year ended December 31, 2022 by $195.4 million, or 184% compared to 2021, primarily due to a 
$181.8 million increase in DD&A related to the assets acquired in the Acquisitions and a $13.6 million increase in DD&A 
driven by higher production volumes and increased depletable costs related to the development of our properties which were 
also affected by increased costs due to inflation in 2022.
General and administrative expense (“G&A”)
G&A for the year ended December 31, 2022 increased by $32.3 million, or 77% compared to 2021, primarily due to an increase 
of $14.4 million in stock-based compensation expense. The remainder of the increase was due to an increase of $13.4 million in 
payroll and employee costs associated with increased headcount and $4.9 million primarily related to an increase in 
professional fees due to overall increased operating activity and increased costs due to inflation in 2022.
60

Transaction costs
For the year ended December 31, 2022, transaction costs increased by $3.4 million compared to 2021, primarily due to legal 
and professional fees associated with the 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, 2021, to $66.8 million for the year ended 
December 31, 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 the 8.000% Senior Notes 
in April 2022, as well as higher interest rates under the Credit Agreement during 2022. See Note 12. Long-Term Debt in the 
Notes to Consolidated Financial Statements.
Loss on derivative contracts, net
For the year ended December 31, 2022, we recorded a net loss on derivative contracts of $125.1 million, consisting of net 
realized losses on settlements of our commodity hedges of $195.9 million, partially offset by unrealized mark-to-market gains 
of $70.8 million related to our commodity hedges. For the year ended December 31, 2021, we recorded a net loss on derivative 
contracts of $116.8 million, consisting of net realized losses on settlements of our commodity hedges of $76.9 million partially 
offset by net realized gains on our interest rate swap of $0.9 million, along with unrealized mark-to-market losses of $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 expense
During the year ended December 31, 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, 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 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 loss from EEH, which was offset 
by a valuation allowance as future realization of the net deferred tax asset cannot be assured and (3) current income tax expense 
of $0.63 million, all of which is related to state income tax expense and (4) 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.
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 $775 million which we expect to be funded by cash flows from operations. During the year 
ended December 31, 2022, 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 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 commodity prices, operating costs and volumes produced, all of 
which affect us and our industry. We have no control over market prices for oil, natural gas or natural gas liquids, although we 
may be able to influence the amount of realized revenues through the use of derivative contracts as part of our commodity price 
risk management.
We believe we will have sufficient liquidity with cash flows from operations and borrowings under 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 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 pace of development, production volumes, changes in our 
hedging activities, realized commodity prices and differentials to NYMEX prices for our oil and natural gas production will 
continue to be the largest variables affecting our working capital.
We expect to finance future development activities with cash flows from operating activities, borrowings under the Credit 
Agreement and various means of corporate and project financing. Additionally, we may continue to partially finance our 
drilling activities through the sale of participating rights to financial institutions or industry participants, and we could structure 
such arrangements on a promoted basis, whereby we may earn working interests in reserves and production greater than our 
proportionate share of capital costs.
62

Cash Flows from Operating Activities
Cash flows provided by operating activities for the year ended December 31, 2022 increased to $1.0 billion compared to $230.9 
million for the year ended December 31, 2021, primarily due to the impact of the Acquisitions and the timing of payments and 
receipts partially offset by the cash settlement payments of derivative contracts as compared to the prior year.
Cash Flows from Investing Activities
Cash flows used in investing activities for the year ended December 31, 2022 increased to $2.0 billion from $426.2 million for 
the year ended December 31, 2021, due to approximately $1.5 billion in acquisitions of oil and gas properties, $491.8 million 
related to the execution of our developmental program and $2.1 million related to other property additions, partially offset by 
$49.5 million in proceeds from sales of oil and gas properties.
Cash Flows from Financing Activities
Cash flows provided by financing activities for the year ended December 31, 2022 increased to $945.3 million from $197.9 
million for the year ended December 31, 2021. On April 12, 2022, we issued $550.0 million of 8.000% senior notes due 2027 
for net 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, partially offset by $43.9 million paid to repurchase 3.0 
million shares of our Class A Common Stock in late 2022.
Capital Expenditures
Our accrual basis capital expenditures for the years ended December 31, 2022, 2021 and 2020 were as follows:
 
Years Ended December 31,
(In thousands)
2022
2021
2020
Drilling and completions
$ 
529,478 
$ 
127,884 $ 
66,580 
Leasehold costs
 
1,118 
 
2,608  
208 
Total capital expenditures
$ 
530,596 
$ 
130,492 $ 
66,788 
Hedging Activities
The following table sets forth our outstanding derivative contracts at December 31, 2022. When aggregating multiple contracts, 
the weighted average contract price is disclosed.
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 WTI Midland Argus Crude and the WTI NYMEX.
(2)
The basis differential price is between W. Texas (WAHA) and the Henry Hub NYMEX.
 
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 
63

Hedging Update
The following table sets forth our outstanding derivative contracts at March 1, 2022. When aggregating multiple contracts, the 
weighted average contract price is disclosed.
Period
Commodity
Volume
(Bbls / MMBtu)
Price
($/Bbl / $/MMBtu)
2023
Crude Oil Swap
1,377,000
$76.94
2023
Crude Oil Basis Swap(1)
7,925,000
$0.92
2023
Natural Gas Swap
3,670,000
$3.35
2023
Natural Gas Basis Swap(2)
42,840,000
$(1.67)
2024
Natural Gas Basis Swap(2)
36,600,000
$(1.05)
(1)
The basis differential price is between WTI Midland Argus Crude and the WTI NYMEX.
(2)
The basis differential price is between W. Texas (WAHA) and the Henry Hub NYMEX.
 
Costless Collars
Period
Commodity
Volume
(Bbls / MMBtu)
Bought Floor
($/Bbl / $/MMBtu)
Sold Ceiling
($/Bbl / $/MMBtu)
2023
Crude Oil Costless Collar
2,356,200
$ 
62.47 $ 
87.56 
2023
Natural Gas Costless Collar
17,190,700
$ 
3.54 $ 
6.33 
 
Deferred Premium Puts
Period
Commodity
Volume
(Bbls / MMBtu)
$/Bbl (Put Price)
$/Bbl (Net of Premium)
2023
Crude Oil
 
1,559,800 $ 
69.61 $ 
64.19 
Obligations and Commitments
We had the following contractual obligations and commitments as of December 31, 2022:
(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:
•
The quality and quantity of available data;
•
The interpretation of that data;
•
The accuracy of various mandated economic assumptions; and
•
The judgments of the persons preparing the estimates.
Our proved reserves information included in this report is based on estimates prepared by our independent petroleum engineers, 
CG&A. The independent petroleum engineers evaluated 100% of our estimated proved reserve quantities and their related 
future net cash flows as of December 31, 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.
Depreciation, Depletion and Amortization
Our rate of recording DD&A is dependent upon our estimates of total proved and proved developed reserves, which estimates 
incorporate various assumptions and future projections. If the estimates of total proved or proved developed reserves decline, 
the rate at which we record DD&A expense increases, reducing our net income. Such a decline in reserves may result from 
lower commodity prices, which may make it uneconomic to drill for and produce higher cost fields. We are unable to predict 
changes in reserve quantity estimates as such quantities are dependent on the success of our exploitation and development 
program, as well as future economic conditions.
65

Impairment of Oil and Natural Gas Properties
We review the value of our oil and natural gas properties whenever management judges that events and circumstances indicate 
that the recorded carrying value of properties may not be recoverable. Impairments of producing properties are determined by 
comparing the pretax future net undiscounted cash flows to the net book value at the end of each period. If the net capitalized 
cost exceeds undiscounted future cash flows, the cost of the property is written down to “fair value,” which is determined based 
on expected future cash flows using discount rates commensurate with the risks involved, using prices and costs consistent with 
those used for internal decision making. Different pricing assumptions or discount rates could result in a different calculated 
impairment. We provide for impairments on significant undeveloped properties when we determine that the property will not be 
developed or a permanent impairment in value has occurred.
Asset Retirement Obligation
Our asset retirement obligations (“AROs”) consist primarily of estimated future costs associated with the plugging and 
abandonment of oil and natural gas wells, removal of equipment and facilities from leased acreage, and land restoration in 
accordance with applicable local, state and federal laws. The discounted fair value of an ARO liability is required to be 
recognized in the period in which it is incurred, with the associated asset retirement cost capitalized as part of the carrying cost 
of the oil and natural gas asset. The recognition of an ARO requires that management make numerous assumptions regarding 
such factors as the estimated probabilities, amounts and timing of settlements; the credit-adjusted risk-free rate to be used; 
inflation rates; and future advances in technology. In periods subsequent to the initial measurement of the ARO, we must 
recognize period-to-period changes in the liability resulting from the passage of time and revisions to either the timing or the 
amount of the original estimate of undiscounted cash flows. Increases in the ARO liability due to passage of time impact net 
income as accretion expense. The related capitalized cost, including revisions thereto, is charged to expense through DD&A 
over the life of the field.
Derivative Instruments and Hedging Activity
We are exposed to certain risks relating to our ongoing business operations, such as commodity price risk. Derivative contracts 
are utilized to economically hedge our exposure to price fluctuations and reduce the variability in our cash flows associated 
with anticipated sales of future oil and natural gas production. We follow FASB Accounting Standards Codification (“ASC”) 
Topic 815, Derivatives and Hedging, to account for our derivative financial instruments. We do not enter into derivative 
contracts for speculative trading purposes. It is our policy to enter into derivative contracts only with counterparties that are 
creditworthy financial institutions deemed by management as competent and competitive. We did not post collateral under any 
of these contracts.
Our crude oil and natural gas derivative positions consist of fixed price swaps, basis swaps and costless collars. Swaps 
exchange floating price risk in the future for a fixed price at the time of the hedge. Costless collars set both a maximum (sold 
ceiling) and a minimum (bought floor) future price. We have elected to not designate any of our derivative contracts for hedge 
accounting. Accordingly, we record the net change in the mark-to-market valuation of these derivative contracts, as well as all 
payments and receipts on settled derivative contracts, in “(Loss) gain on derivative contracts, net” on the Consolidated 
Statements of Operations. All derivative contracts are recorded at fair market value and are included in the Consolidated 
Balance Sheets as assets or liabilities.
Stock-Based Compensation
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.
Income Taxes
We are a U.S. company operating in Texas and New Mexico, as of December 31, 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 
66

involves estimating the actual current tax exposure together with assessing temporary differences resulting from differing 
treatment of items, such as depreciation, amortization and certain accrued liabilities for tax and accounting purposes. Our 
effective tax rate for financial statement purposes will continue to fluctuate from year to year as our operations are conducted in 
different taxing jurisdictions.
Our corporate structure requires the filing of two separate consolidated U.S. Federal income tax returns and one Canadian 
income tax return resulting from Earthstone’s acquisition of Lynden Corp in 2016 (the “Lynden Arrangement”) that includes 
Lynden US, Earthstone, and Lynden Corp. As such, taxable income of Earthstone cannot be offset by tax attributes, including 
net operating losses, of Lynden US, nor can taxable income of Lynden US be offset by tax attributes of Earthstone. Earthstone 
and Lynden US record a tax provision, respectively, for their share of the book income or loss of EEH, net of the noncontrolling 
interest, as well as any standalone income or loss generated by each company. As EEH is treated as a partnership for U.S. 
Federal income tax purposes, it is not subject to income tax at the federal level and only recognizes the Texas Margin Tax.
On January 7, 2021, upon closing of the IRM Acquisition, the acquired entity, Independence Resources Management, LLC 
(along with its wholly owned subsidiaries, collectively “IRM”), became a wholly owned subsidiary of EEH. IRM’s 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, 2022 and 2021, we recorded a valuation 
allowance for our deferred tax assets in the Consolidated Balance Sheets.
On February 15, 2022, as a result of the completion of the 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 Internal Revenue Code of 1986, as 
amended (the “Code”). We are currently assessing the impact of the limitation on both our NOL and our deferred tax asset. 
Revenue Recognition
We predominantly derive our revenue from the sale of produced oil, natural gas and natural gas liquids. Revenues are 
recognized when the recognition criteria of FASB ASC Topic 606, Revenue from Contracts with Customers, are met, which 
generally occurs at the point in which title passes to the customers. We receive payment from one to three months after 
delivery. At the end of each quarter, we estimate the amount of production delivered to purchasers and the price we will 
receive. Variances between our estimated revenue and actual payment are recorded in the month the payment is 
received. Historically, however, differences have been insignificant.
Accounting for Business Combinations
Our business has grown substantially through acquisitions, and our business strategy is to continue to pursue acquisitions as 
opportunities arise. We have accounted for all of our business combinations to date using the purchase method.
Under the purchase method of accounting, a business combination is accounted for at a purchase price based upon the fair value 
of the consideration given. The assets and liabilities acquired are measured at their fair value including the recognition of 
acquisition-related costs that are separate from the acquired net assets. The purchase price is allocated to the assets and 
liabilities based upon these fair values. The excess of the cost of an acquired entity, if any, over the net amounts assigned to 
assets acquired and liabilities assumed is recognized as goodwill. The excess of the fair value of assets acquired and liabilities 
assumed over the cost of an acquired entity, if any, is allocated as a pro rata reduction of the amounts that otherwise would have 
been assigned to certain acquired assets.
Determining the fair values of the assets and liabilities acquired involves the use of judgment, since some of the assets and 
liabilities acquired do not have fair values that are readily determinable. Different techniques may be used to determine fair 
values, including market prices (where available), appraisals, and comparison to transactions for similar assets and liabilities, 
and present value of estimated future cash flows, among others. Since these estimates involve the use of significant judgment, 
they can change as new information becomes available.
Noncontrolling Interest
We account for noncontrolling interest in accordance with FASB ASC Topic 810, Consolidation, which requires the recording 
of a noncontrolling interest component of Net income (loss), as well as a noncontrolling interest component within 
equity. Noncontrolling interest represents third-party equity ownership of EEH and is presented as a component of equity in the 
Consolidated Balance Sheet as of December 31, 2022 and 2021, as well as an adjustment to Net income (loss) in the 
67

Consolidated Statement of Operations for the years ended December 31, 2022 and 2021. See further discussion in Note 2. 
Noncontrolling Interest in the Notes to Consolidated Financial Statements.
Recently Issued Accounting Standards
See Note 3. Summary of Significant Accounting Policies in the Notes to Consolidated Financial Statements under Item 8 of this 
report for a discussion of recently issued accounting standards affecting us.
Item 7A. Quantitative and Qualitative Disclosures About Market Risk
We are exposed to market risks associated with interest rate risks, commodity price risk and credit risk. We have established 
risk management processes to monitor and manage these market risks.
Commodity Price Risk, Derivative Instruments and Hedging Activity
We are exposed to various risks including energy commodity price risk. When oil, natural gas and natural gas 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 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. 
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 premium is not paid until the expiration of the option.
We have entered into a series of derivative instruments to hedge a portion of our expected oil and natural gas production 
through December 31, 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, 2022:
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 WTI Midland Argus Crude and the WTI NYMEX.
(2)
The basis differential price is between W. Texas (WAHA) and the Henry Hub NYMEX.
 
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 
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 $26.4 million at December 31, 2022. 
Based on the published commodity futures price curves for the underlying commodity as of December 31, 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 $1.1 million to an overall net asset position of $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 $1.1 
million to an overall net asset position of $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.
68

Interest Rate Sensitivity
We are also exposed to market risk related to adverse changes in interest rates. Our interest rate risk exposure results primarily 
from fluctuations in short-term rates, which are based on SOFR and the prime rate and may result in reductions of earnings or 
cash flows due to increases in the interest rates we pay on these obligations.
At December 31, 2022, the outstanding borrowings under the revolving tranche and term loan tranche of the Credit Agreement 
were $520.1 million bearing interest at rates described in Note 12. Long-Term Debt in the Notes to Consolidated Financial 
Statements. Fluctuations in interest rates will cause our annual interest costs to fluctuate. At December 31, 2022, the weighted 
average interest rate on borrowings under the revolving tranche and term loan tranche of the Credit Agreement was 7.446% per 
year. If borrowings at December 31, 2022 were to remain constant, a 10% change in interest rates would impact our future cash 
flows by approximately $3.9 million per year.
Credit Risk 
Credit risk represents the potential financial loss that we would record if our purchasers, operators, or counterparties failed to 
perform pursuant to contractual terms. Our primary concentration of credit risks are associated with the collection of 
receivables resulting from the sale of oil, natural gas and natural gas liquids production and purchased oil, natural gas and 
natural gas liquids; the risk of a counterparty's failure to meet its obligations under derivative contracts with us; and amounts of 
deposit in excess of Federal Deposit Insurance Corporation (“FDIC”) insurance coverage. See Note 3. Summary of Significant 
Accounting Policies in the Notes to Consolidated Financial Statements for additional information.
Disclosure of Limitations
Because the information above included only those exposures that existed at December 31, 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.
Item 8. Financial Statements and Supplementary Data
See Index to Consolidated Financial Statements and Supplementary Information on Page F-1.
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
None.
Item 9A. Controls and Procedures
Internal Control Over Financial Reporting
Evaluation of Disclosure Controls and Procedures
(a) Disclosure Controls and Procedures
We maintain disclosure controls and procedures that are designed to provide reasonable assurance that information required to 
be disclosed by us in the reports that we file or submit to the SEC under the Exchange Act, is recorded, processed, summarized 
and reported within the time periods specified by the SEC’s rules and forms, and that information is accumulated and 
communicated to our management, including our Chief Executive Officer and Principal Accounting Officer, as appropriate to 
allow timely decisions regarding required disclosure.
In accordance with Rules 13a-15(b) and 15d-15(b) under the Exchange Act, we carried out an evaluation, under the supervision 
and with the participation of management, including our Chief Executive Officer and Principal Accounting Officer, of the 
effectiveness of our disclosure controls and procedures (as defined by Rules 13a-15(e) and 15d-15(e) under the Exchange Act) 
as of the end of the period covered by this Annual Report on Form 10-K. As described below under paragraph (b) within 
Management’s Annual Report on Internal Control over Financial Reporting, our Chief Executive Officer and Principal 
Accounting Officer have concluded that, as of the end of the period covered by this Annual Report on Form 10-K, our 
disclosure controls and procedures were effective to provide reasonable assurance that information required to be disclosed by 
us in the reports that we file or submit to the SEC under the Exchange Act is recorded, processed, summarized and reported 
within the time periods specified by the SEC’s rules and that such information is accumulated and communicated to our 
management, including our Chief Executive Officer and Principal Accounting Officer, as appropriate to allow timely decisions 
regarding required disclosure.
The audit report of our independent registered public accounting firm, which is included in this Annual Report on Form 10-K, 
expressed an unqualified opinion on our consolidated financial statements.
69

(b) Management’s Annual Report on Internal Control over Financial Reporting
Our management is responsible for establishing and maintaining adequate internal control over financial reporting as defined in 
Rules 13a-15(f) and 15d-15(f) under the Exchange Act. Our internal control over financial reporting is designed to provide 
reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external 
purposes in accordance with generally accepted accounting principles. Our internal control over financial reporting includes 
those policies and procedures that:
•
pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect our transactions 
and dispositions of our assets;
•
provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial 
statements in accordance with generally accepted accounting principles, and that our receipts and 
expenditures are being made only in accordance with authorizations of our management; and
•
provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or 
disposition of our assets that could have a material effect on the financial statements.
While “reasonable assurance” is a high level of assurance, it does not mean absolute assurance. Because of its inherent 
limitations, internal control over financial reporting may not prevent or detect every misstatement and instance of fraud. 
Controls are susceptible to manipulation, especially in instances of fraud caused by collusion of two or more people. Also, 
projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate 
because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
Under the supervision and with the participation of our Chief Executive Officer and Principal Accounting Officer, our 
management conducted an evaluation of the effectiveness of our internal control over financial reporting as of December 31, 
2022. In making this evaluation, management used the Internal Control – Integrated Framework (2013) issued by the 
Committee of Sponsoring Organizations of the Treadway Commission (“COSO”). Based on the results of our evaluation, our 
management concluded that our internal control over financial reporting was effective, at the reasonable assurance level, as of 
December 31, 2022.
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, 2022, which is included 
herein.
(c) Changes in Internal Control over Financial Reporting
There have not been any changes in our internal control over financial reporting during the quarter ended December 31, 2022 
that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
70

Report of Independent Registered Public Accounting Firm
To the Shareholders and the Board of Directors of 
Earthstone Energy, Inc.
Opinion on Internal Control over Financial Reporting
We have audited Earthstone Energy, Inc. and subsidiaries (the “Company”) internal control over 
financial reporting as of December 31, 2022, based on criteria established in Internal Control - 
Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway 
Commission (“COSO”). In our opinion, the Company maintained, in all material respects, effective 
internal control over financial reporting as of December 31, 2022, based on criteria established in 
Internal Control - Integrated Framework (2013) issued by COSO.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight 
Board (United States) (“PCAOB”), the consolidated balance sheets of Earthstone Energy, Inc. and 
subsidiaries as of December 31, 2022 and 2021, the related consolidated statements of operations, 
stockholders’ equity and cash flows for each of the three years in the period ended December 31, 
2022, and the related notes (collectively referred to as the “consolidated financial statements”) and 
our report dated March 8, 2023 expressed an unqualified opinion on those consolidated financial 
statements.
Basis for Opinion
The Company’s management is responsible for maintaining effective internal control over financial 
reporting and for its assessment of the effectiveness of internal control over financial reporting, 
included in the accompanying Management Report on Internal Control over Financial Reporting 
included in Item 9A. Our responsibility is to express an opinion on the Company’s internal control over 
financial reporting based on our audit. We are a public accounting firm registered with the PCAOB 
and are required to be independent with respect to the Company in accordance with the U.S. federal 
securities laws and the applicable rules and regulations of the Securities and Exchange Commission 
and the PCAOB.
We conducted our audit in accordance with the standards of the PCAOB. Those standards require 
that we plan and perform the audit to obtain reasonable assurance about whether effective internal 
control over financial reporting was maintained in all material respects. Our audit included obtaining 
an understanding of internal control over financial reporting, assessing the risk that a material 
weakness exists, and testing and evaluating the design and operating effectiveness of internal control 
based on the assessed risk. Our audit also included performing such other procedures as we 
considered necessary in the circumstances. We believe that our audit provides a reasonable basis for 
our opinion.
Definition and Limitations of Internal Control Over Financial Reporting
A company’s internal control over financial reporting is a process designed to provide reasonable 
assurance regarding the reliability of financial reporting and the preparation of financial statements for 
external purposes in accordance with generally accepted accounting principles. A company’s internal 
control over financial reporting includes those policies and procedures that (1) pertain to the 
maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and 
dispositions of the assets of the company; (2) provide reasonable assurance that transactions are 
recorded as necessary to permit preparation of financial statements in accordance with generally 
accepted accounting principles, and that receipts and expenditures of the company are being made 
only in accordance with authorizations of management and directors of the company; and (3) provide 
reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or 
disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect 
misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the 
71

risk that controls may become inadequate because of changes in conditions, or that the degree of 
compliance with the policies or procedures may deteriorate.
/s/ Moss Adams LLP
Houston, Texas
March 8, 2023
We have served as the Company’s auditor since 2018.
72

Item 9B. Other Information
None.
Item 9C. Disclosure Regarding Foreign Jurisdictions that Prevent Inspections
Not applicable.
PART III
Item 10. Directors, Executive Officers and Corporate Governance
See list of “Information about our Executive Officers” under Item 1 of this report, which is incorporated herein by reference.
The other information required by this item is incorporated herein by reference to the Proxy Statement, which will be filed with 
the SEC not later than 120 days subsequent to December 31, 2022.
Item 11. Executive Compensation
The information required by this item is incorporated herein by reference to the Proxy Statement, which will be filed with the 
SEC not later than 120 days subsequent to December 31, 2022.
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
The information required by this item is incorporated herein by reference to the Proxy Statement, which will be filed with the 
SEC not later than 120 days subsequent to December 31, 2022.
Item 13. Certain Relationships and Related Transactions, and Director Independence
The information required by this item is incorporated herein by reference to the Proxy Statement, which will be filed with the 
SEC not later than 120 days subsequent to December 31, 2022.
Item 14. Principal Accountant Fees and Services
The information required by this item is incorporated herein by reference to the Proxy Statement, which will be filed with the 
SEC not later than 120 days subsequent to December 31, 2022.
73

PART IV
Item 15. Exhibit and Financial Statement Schedules
 
 
 
Incorporated by Reference
 
 
Exhibit
No.
Description
Form
SEC File 
No.
Exhibit
Filing Date
Filed
Herewith
Furnished
Herewith
2.1
Contribution Agreement dated 
November 7, 2016, by and among 
Earthstone Energy, Inc., Earthstone 
Energy Holdings, LLC, Lynden USA 
Inc., Lynden USA Operating, LLC, 
Bold Energy Holdings, LLC and Bold 
Energy III LLC.
8-K
001-35049
2.1
November 8, 
2016
 
 
2.1(a)
First Amendment to the Contribution 
Agreement dated March 21, 2017, by 
and among Earthstone Energy, Inc., 
Earthstone Energy Holdings, LLC, 
Lynden USA Inc., Lynden USA 
Operating, LLC, Bold Energy 
Holdings, LLC and Bold Energy III 
LLC.
8-K
001-35049
2.1
March 23, 
2017
 
 
2.2
Purchase and Sale Agreement dated as 
of December 17, 2020, by and among 
Earthstone Energy, Inc., Earthstone 
Energy Holdings, LLC, Independence 
Resources Holdings, LLC and 
Independence Resources Manager, 
LLC.
8-K
001-35049
2.1
December 
22, 2020
 
 
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
74

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
75

10.9(a)†
First Amendment to the Earthstone 
Energy, Inc. Amended and Restated 
2014 Long-Term Incentive Plan dated 
June 3, 2020.
8-K
001-35049
10.1
June 5, 2020
10.9(b)†
Amendment No. 2 to the Earthstone 
Energy, Inc. Amended and Restated 
2014 Long-Term Incentive Plan dated 
July 20, 2021.
8-K
001-35049
10.5
July 23, 2021
10.10†
Form of Performance Unit Agreement 
(Executive Management).
8-K
001-35049
10.2
February 1, 
2019
10.11†
Earthstone Energy, Inc. Second 
Amended and Restated Change in 
Control and Severance Benefit Plan.
8-K
001-35049
10.5
January 12, 
2023
10.12
Credit Agreement dated November 
21, 2019, by and among Earthstone 
Energy Holdings, LLC, as Borrower, 
Earthstone Energy, Inc., as Parent, 
Wells Fargo Bank, National 
Association as Administrative Agent 
and Issuing Bank, BOKF, NA dba 
Bank of Texas, as Issuing Bank with 
respect to Existing Letters of Credit, 
Royal Bank of Canada, as Syndication 
Agent, SunTrust Bank, as 
Documentation Agent, and the 
Lenders party thereto.
8-K
001-35049
10.1
November 
22, 2019
10.12(a)
First Amendment to Credit Agreement 
dated September 28, 2020, by and 
among Earthstone Energy Holdings, 
LLC, as Borrower, Earthstone Energy, 
Inc., as Parent, the Guarantors party 
thereto, Wells Fargo Bank, National 
Association as Administrative Agent, 
and the Lenders party thereto.
8-K
001-35049
10.1
October 1, 
2020
10.12(b)
Second Amendment to Credit 
Agreement dated December 17, 2020, 
by and among Earthstone Energy 
Holdings, LLC, as Borrower, 
Earthstone Energy, Inc., as Parent, the 
Guarantors party thereto, Wells Fargo 
Bank, National Association as 
Administrative Agent, and the 
Lenders party thereto.
8-K
001-35049
10.1
December 
22, 2020
10.12(c)
Third Amendment to Credit 
Agreement dated as of April 20, 2021, 
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
April 20, 
2021
10.12(d)
Fourth Amendment to Credit 
Agreement dated as of September 17, 
2021, 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
September 
20, 2021
10.12(e)
Fifth Amendment to Credit 
Agreement dated as of December 24, 
2021, 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
December 
29, 2021
76

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
77

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
78

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
79

23.2
Consent of Moss Adams LLP.
 
 
 
 
X
31.1
Certification of the Principal 
Executive Officer pursuant to Section 
302 of the Sarbanes-Oxley Act.
 
 
 
 
X
31.2
Certification of the Principal Financial 
Officer pursuant to Section 302 of the 
Sarbanes-Oxley Act.
 
 
 
 
X
 
32.1
Certification of the Chief Executive 
Officer pursuant to Section 906 of the 
Sarbanes-Oxley Act.
 
 
 
 
 
X
32.2
Certification of the Executive Vice 
President - Accounting and 
Administration pursuant to Section 
906 of the Sarbanes-Oxley Act.
 
 
 
 
 
X
99.1
Report of Cawley, Gillespie & 
Associates, Inc.
 
 
 
 
X
 
101.INS
XBRL Instance Document.
 
 
 
 
X
 
101.SCH
XBRL Schema Document.
 
 
 
 
X
 
101.CAL
XBRL Calculation Linkbase 
Document.
 
 
 
 
X
 
101.DEF
XBRL Definition Linkbase 
Document.
 
 
 
 
X
 
101.LAB
XBRL Label Linkbase Document.
 
 
 
 
X
 
101.PRE
XBRL Presentation Linkbase 
Document.
 
 
 
 
X
 
104
Cover Page Interactive Data File 
(embedded within the Inline XBRL 
document).
X
†
Indicates management contract or compensatory plan or arrangement.
Item 16. Form 10-K Summary
None.
80

SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this 
report to be signed on its behalf by the undersigned, thereunto duly authorized.
 
 
EARTHSTONE ENERGY, INC.
 
 
 
 
By:
/s/ Robert J. Anderson
 
Name:
Robert J. Anderson
Date:
March 8, 2023
Title:
President, Chief Executive Officer and Director
 
 
(Principal Executive Officer)
 
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following 
persons on behalf of the registrant and in the capacities and on the dates indicated. 
Signature
Title
Date
 
 
 
/s/ Robert J. Anderson
President, Chief Executive Officer and Director
(Principal Executive Officer)
March 8, 2023
Robert J. Anderson
 
 
 
/s/ Tony Oviedo
Executive Vice President, Accounting and Administration 
(Principal Financial Officer and Principal Accounting Officer)
March 8, 2023
Tony Oviedo
/s/ Frank A. Lodzinski
Executive Chairman
March 8, 2023
Frank A. Lodzinski
/s/ Frost Cochran
Director
March 8, 2023
Frost Cochran
/s/ David S. Habachy
Director
March 8, 2023
David S. Habachy
 
 
 
/s/ Jay F. Joliat
Director
March 8, 2023
Jay F. Joliat
 
 
 
/s/ Phil D. Kramer
Director
March 8, 2023
Phil D. Kramer
 
 
 
 
 
/s/ Ray Singleton
Director
March 8, 2023
Ray Singleton
 
 
 
/s/ Douglas E. Swanson, Jr.
Director
March 8, 2023
Douglas E. Swanson, Jr.
 
 
 
 
 
/s/ Brad A. Thielemann
Director
March 8, 2023
Brad A. Thielemann
 
 
 
/s/ Zachary G. Urban
Director
March 8, 2023
Zachary G. Urban
 
 
 
/s/ Robert L. Zorich
Director
March 8, 2023
Robert L. Zorich
81

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

Report of Independent Registered Public Accounting Firm
To the Shareholders and the Board of Directors of 
Earthstone Energy, Inc.
Opinion on the Financial Statements
We have audited the accompanying consolidated balance sheets of Earthstone Energy, Inc. and 
subsidiaries (the “Company”) as of December 31, 2022 and 2021, the related consolidated 
statements of operations, equity, and cash flows for each of the three years in the period ended 
December 31, 2022, and the related notes (collectively referred to as the “consolidated financial 
statements”). In our opinion, the consolidated financial statements present fairly, in all material 
respects, the consolidated financial position of the Company as of December 31, 2022 and 2021, and 
the consolidated results of its operations and its cash flows for each of the three years in the period 
ended December 31, 2022, in conformity with accounting principles generally accepted in the United 
States of America.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight 
Board (United States) (“PCAOB”), the Company’s internal control over financial reporting as of 
December 31, 2022, based on criteria established in Internal Control - Integrated Framework (2013) 
issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report 
dated March 8, 2023 expressed an unqualified opinion on the Company’s internal control over 
financial reporting.
Basis for Opinion
These consolidated financial statements are the responsibility of the Company’s management. Our 
responsibility is to express an opinion on the Company’s consolidated financial statements based on 
our audits. We are a public accounting firm registered with the PCAOB and are required to be 
independent with respect to the Company in accordance with the U.S. federal securities laws and the 
applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require 
that we plan and perform the audit to obtain reasonable assurance about whether the consolidated 
financial statements are free of material misstatement, whether due to error or fraud. Our audits 
included performing procedures to assess the risks of material misstatement of the consolidated 
financial statements, whether due to error or fraud, and performing procedures to respond to those 
risks. Such procedures included examining, on a test basis, evidence regarding the amounts and 
disclosures in the consolidated financial statements. Our audits also included evaluating the 
accounting principles used and significant estimates made by management, as well as evaluating the 
overall presentation of the consolidated financial statements. We believe that our audits provide a 
reasonable basis for our opinion.
Critical Audit Matters
The critical audit matters communicated below are matters arising from the current period audit of the 
(consolidated) financial statements that were communicated or required to be communicated to the 
audit committee and that (1) relate to accounts or disclosures that are material to the consolidated 
financial statements and (2) involved our especially challenging, subjective, or complex judgments. 
The communication of critical audit matters does not alter in any way our opinion on the consolidated 
financial statements, taken as a whole, and we are not, by communicating the critical audit matters 
below, providing a separate opinion on the critical audit matters or on the accounts or disclosures to 
which they relate.
Assessment of the Estimated Proved Oil and Gas Reserves on the Determination of Depreciation, 
Depletion and Amortization Expense related to Proved Oil and Natural Gas Properties
The Company’s net proved oil and natural gas properties balance was $3,657 million as of December 
31, 2022, and the associated depreciation, depletion and amortization (DD&A) expense for the year 
F-2

ended December 31, 2022 was $302 million. As described in Note 7 to the consolidated financial 
statements, the Company follows the successful efforts method of accounting for its oil and natural 
gas properties. The Company’s lease acquisition costs and development costs of proved oil and 
natural gas properties are amortized using the units-of-production method, at the field level, based on 
total estimated proved oil and natural gas reserves and estimated proved developed oil and natural 
gas reserves, respectively. 
The principal considerations for our determination that performing procedures relating to the impact of 
proved oil and natural gas reserves on proved net oil and natural gas properties is a critical audit 
matter are there was (i) significant judgment by management, including the use of specialists, when 
developing the estimates of proved oil and natural gas reserves; (ii) a high degree of auditor 
judgment, subjectivity and effort in performing procedures and evaluating management’s significant 
assumptions related to developing those estimates, including future production amounts and costs, 
historical oil and natural gas prices, pricing differentials, and future development costs including the 
Company’s ability to convert proved undeveloped reserves to producing properties within five years of 
their initial proved booking.
Addressing the matter involved performing procedures and evaluating audit evidence in connection 
with forming our overall opinion on the consolidated financial statements. The procedures we 
performed to address this critical audit matter included:
(i)
Obtaining an understanding, evaluating the design and testing the operating effectiveness of 
controls over the Company’s process to calculate DD&A, including management’s controls over 
the completeness and accuracy of the financial data provided to the Company’s engineering 
technical team and independent petroleum engineering consulting firm for use in estimating the 
proved oil and gas reserves; 
(ii) Evaluating the significant assumptions used by management in developing these estimates, 
including future production, historical oil and gas prices, pricing differentials, and future 
development costs; 
(iii) Evaluating management’s development plan for compliance with the SEC rule that undrilled 
locations are scheduled to be drilled within five years, by assessing consistency of the 
development projections with the Company’s drill plan and the availability of capital relative to 
the drill plan; 
(iv) Utilizing the work of management’s specialists to evaluate the reasonableness of the estimates 
of proved oil and natural gas reserves. As a basis for this work, the specialists’ qualifications 
and objectivity were assessed, as well as the reasonableness of methods and assumptions 
used by the specialists. The procedures performed also included testing the data used by the 
specialists and evaluating the specialists’ findings. Evaluating the significant assumptions 
relating to the estimates of proved oil and natural gas reserves also involved obtaining 
evidence to support whether the assumptions used were consistent with the past performance 
of the Company, and whether they were consistent with evidence obtained in other areas of the 
audit; 
(v) Testing the inputs of and recalculating management’s DD&A calculation.
Acquisition of Chisholm Energy Operating, LLC and Chisholm Energy Agent, Inc (collectively 
“Chisholm”) - Valuation of Proved Oil and Natural Gas Properties
As described in Note 4 to the consolidated financial statements, $633.5 million was allocated to 
proved oil and natural gas properties related to the purchase price of Chisholm on February 15, 2022. 
As disclosed by management, the Company accounts for business combinations under the 
acquisition method of accounting. Accordingly, the Company recognizes amounts for identifiable 
assets acquired and liabilities assumed equal to their estimated acquisition date fair values. The fair 
value estimate of proved oil and natural gas properties as of an acquisition date was based on 
estimated proved oil and natural gas reserves and related future net cash flows discounted using a 
weighted average cost of capital, including estimates and assumptions of future commodity prices 
and costs, the timing of development activities, projections of oil and natural gas reserves and 
estimates to abandon and reclaim producing wells. As disclosed by management, the accuracy of the 
reserve estimates is a function of the quality of data available and of engineering and geological 
interpretation and judgment. In addition, estimates of reserves may be revised based on actual 
F-3

production, results of subsequent exploration and development activities, recent commodity prices, 
operating costs and other factors. The estimates of oil and natural gas reserves have been developed 
by specialists, specifically petroleum engineers. 
The principal considerations for our determination that performing procedures relating to the 
allocation and valuation of proved oil and natural gas properties acquired in the Chisholm acquisition 
is a critical audit matter are the (i) the significant judgment by management, including the use of 
specialists, when determining the fair value of the acquired oil and gas properties, which in turn led to 
(ii) a high degree of auditor judgment, subjectivity, and effort in performing procedures and evaluating 
management’s significant assumptions related to production volumes, future commodity prices and 
price differentials, lease operating costs, reserve risk adjustment factors, and the weighted average 
cost of capital; and (iii) the audit effort involved the use of professionals with specialized skill and 
knowledge.
Addressing the matter involved performing procedures and evaluating audit evidence in connection 
with forming our overall opinion on the consolidated financial statements. The primary procedures we 
performed to address this critical audit matter included:
(i)
Obtaining an understanding, evaluating the design and testing the operating effectiveness of 
controls over the Company’s process to determine the fair value of assets acquired in the 
business combination, including management’s controls over the completeness and accuracy 
of the financial data provided to the Company’s engineering technical team for use in 
estimating the proved oil and gas reserves used in the fair value calculation;
(ii) Gaining an understanding of management’s process for developing the fair value measurement 
of proved natural gas and oil properties; 
(iii) Evaluating the appropriateness of the discounted cash flow model, which included testing the 
completeness and accuracy of underlying data used in the model; and evaluating significant 
assumptions used by management related to future production volumes, future commodity 
prices and price differentials, lease operating costs, risk adjustment factors, as well as the 
weighted average cost of capital. The evaluation of management’s assumption related to future 
commodity prices involved comparing the prices against observable market data. Professionals 
with specialized skill and knowledge were used to assist in the evaluation of the weighted 
average cost of capital assumption and the appropriateness of the discounted cash flow model;
(iv) Evaluating the professional qualifications and objectivity of the Company’s engineer primarily 
responsible for overseeing the preparation of the reserve estimates by the internal engineering 
staff.
(v) Assessing the competence, capability and objectivity of the outside valuation consultants 
engaged by the Company to measure the fair value of the acquired crude oil and natural gas 
properties including the valuation methodology selected.
/s/ Moss Adams LLP
Houston, Texas
March 8, 2023
We have served as the Company’s auditor since 2018.
F-4

EARTHSTONE ENERGY, INC.
CONSOLIDATED BALANCE SHEETS
(In thousands, except share and per share amounts) 
 
December 31,
ASSETS
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 
Oil and gas properties, successful efforts method:
Proved properties
 
3,987,901 
 
1,625,367 
Unproved properties
 
282,589 
 
222,025 
Land
 
5,482 
 
5,382 
Total oil and gas properties
 
4,275,972 
 
1,852,774 
Accumulated depreciation, depletion and amortization
 
(619,196)  
(395,625) 
Net oil and gas properties
 
3,656,776 
 
1,457,149 
Other noncurrent assets:
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
 
9,117 
 
157 
Operating lease right-of-use assets
 
4,569 
 
1,795 
Other noncurrent assets
 
15,280 
 
33,865 
TOTAL ASSETS
$ 
3,937,401 
$ 
1,556,367 
LIABILITIES AND EQUITY
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 
Noncurrent liabilities:
Long-term debt
 
1,053,879 
 
320,000 
Asset retirement obligation
 
29,611 
 
15,471 
Derivative liability
 
— 
 
571 
Deferred tax liability
 
138,336 
 
15,731 
Operating lease liability
 
3,889 
 
1,276 
Finance lease liability
 
876 
 
— 
Other noncurrent liabilities
 
10,509 
 
6,442 
Total noncurrent liabilities
 
1,237,100 
 
359,491 
Commitments and Contingencies (Note 15)
Equity:
Preferred stock, $0.001 par value, 20,000,000 shares authorized; none issued or outstanding
 
— 
 
— 
Series A Convertible Preferred Stock, $0.001 par value, none authorized, issued or outstanding
 
— 
 
— 
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 
F-5

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 
The accompanying notes are an integral part of these consolidated financial statements.
F-6

EARTHSTONE ENERGY, INC.
CONSOLIDATED STATEMENTS OF OPERATIONS
(In thousands, except share and per share amounts)
 
 
Years Ended December 31,
 
2022
2021
2020
REVENUES
 
 
Oil
$ 
1,114,343 
$ 
297,177 
$ 
120,355 
Natural gas
 
303,846 
 
50,809 
 
8,567 
Natural gas liquids
 
276,965 
 
71,657 
 
15,601 
Total revenues
 
1,695,154 
 
419,643 
 
144,523 
OPERATING COSTS AND EXPENSES
Lease operating expense
 
230,515 
 
49,321 
 
29,131 
Production and ad valorem taxes
 
123,054 
 
26,409 
 
9,411 
Rig idle and termination expense
 
— 
 
— 
 
426 
Impairment expense
 
— 
 
— 
 
64,498 
Depreciation, depletion and amortization
 
301,813 
 
106,367 
 
96,414 
General and administrative expense
 
74,175 
 
41,922 
 
28,233 
Transaction costs
 
8,248 
 
4,875 
 
622 
Accretion of asset retirement obligation
 
2,652 
 
1,065 
 
307 
Exploration expense
 
2,492 
 
341 
 
298 
Total operating costs and expenses
 
742,949 
 
230,300 
 
229,340 
Gain on sale of oil and gas properties, net
 
13,900 
 
738 
 
204 
Income (loss) from operations
 
966,105 
 
190,081 
 
(84,613) 
OTHER INCOME (EXPENSE)
Interest expense, net
 
(66,821)  
(10,796)  
(5,232) 
(Loss) gain on derivative contracts, net
 
(125,107)  
(116,761)  
59,899 
Other income, net
 
856 
 
841 
 
400 
Total other (expense) income 
 
(191,072)  
(126,716)  
55,067 
Income (loss) before income taxes
 
775,033 
 
63,365 
 
(29,546) 
Income tax (expense) benefit
 
(124,416)  
(1,859)  
112 
Net income (loss)
 
650,617 
 
61,506 
 
(29,434) 
Less:  Net income (loss) attributable to noncontrolling interest
 
198,132 
 
26,022 
 
(15,887) 
Net income (loss) attributable to Earthstone Energy, Inc.
$ 
452,485 
$ 
35,484 
$ 
(13,547) 
Net income (loss) per common share attributable to Earthstone Energy, Inc.:
Basic
$ 
5.12 
$ 
0.75 
$ 
(0.45) 
Diluted
$ 
4.83 
$ 
0.71 
$ 
(0.45) 
Weighted average common shares outstanding:
Basic
 
88,349,088 
 
47,169,948 
 
29,911,625 
Diluted
 
96,328,217 
 
49,952,093 
 
29,911,625 
 
The accompanying notes are an integral part of these consolidated financial statements.
F-7

EARTHSTONE ENERGY, INC.
CONSOLIDATED STATEMENTS OF EQUITY
(In thousands, except share amounts) 
 
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 
 The accompanying notes are an integral part of these consolidated financial statements.
F-8

EARTHSTONE ENERGY, INC.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(In thousands) 
 
 
Years Ended December 31,
 
2022
2021
2020
Cash flows from operating activities:
 
 
Net income (loss)
$ 
650,617 
$ 
61,506 
$ 
(29,434) 
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Impairment of proved and unproved oil and gas properties
 
— 
 
— 
 
46,878 
Depreciation, depletion and amortization
 
301,813 
 
106,367 
 
96,414 
Accretion of asset retirement obligations
 
2,652 
 
1,065 
 
307 
Impairment of goodwill
 
— 
 
— 
 
17,620 
Gain on sale of oil and gas properties, net
 
(13,900)  
(738)  
(204) 
Gain on sale of office and other equipment
 
(321)  
(140)  
— 
Settlement of asset retirement obligations
 
(910)  
(185)  
(195) 
Total loss (gain) on derivative contracts, net
 
125,107 
 
116,761 
 
(59,899) 
Operating portion of net cash (paid) received in settlement of derivative contracts
 
(195,876)  
(75,966)  
56,044 
Stock-based compensation
 
35,369 
 
21,014 
 
10,054 
Deferred income taxes
 
122,605 
 
1,859 
 
(657) 
Amortization of deferred financing costs
 
5,529 
 
856 
 
322 
Changes in assets and liabilities:
(Increase) decrease in accounts receivable
 
(168,314)  
(19,061)  
11,914 
(Increase) decrease in prepaid expenses and other current assets
 
(16,282)  
58 
 
(203) 
Increase (decrease) in accounts payable and accrued expenses
 
68,726 
 
9,293 
 
481 
Increase (decrease) in revenues and royalties payable
 
98,840 
 
5,985 
 
(8,323) 
Increase (decrease) in advances
 
3,224 
 
2,200 
 
(9,617) 
Net cash provided by operating activities
 
1,018,879 
 
230,874 
 
131,502 
Cash flows from investing activities:
Acquisition of oil and gas properties (net of cash acquired)
 
(1,523,813)  
(311,324)  
— 
Additions to oil and gas properties
 
(491,836)  
(114,521)  
(88,097) 
Additions to office and other equipment
 
(2,133)  
(1,365)  
(114) 
Proceeds from sale of oil and gas properties
 
49,546 
 
975 
 
414 
Net cash used in investing activities
 
(1,968,236)  
(426,235)  
(87,797) 
Cash flows from financing activities:
Proceeds from borrowings under Credit Agreement
 
3,096,013 
 
744,132 
 
136,056 
Repayments of borrowings under Credit Agreement
 
(3,145,877)  
(539,132)  
(191,056) 
Proceeds from issuance of 8% Senior Notes due 2027, net
 
537,256 
 
— 
 
— 
Proceeds from term loan
 
244,191 
 
— 
 
— 
Proceeds from issuance Series A Convertible Preferred Stock, net of offering costs of $674
 
279,326 
 
— 
 
— 
Cash paid to repurchase Class A Common Stock
 
(43,937)  
— 
 
— 
Cash paid related to the exchange and cancellation of Class A Common Stock
 
(5,829)  
(4,144)  
(836) 
Cash paid for finance leases
 
(649)  
(70)  
(130) 
Deferred financing costs
 
(15,150)  
(2,906)  
(67) 
Net cash provided by (used in) financing activities
 
945,344 
 
197,880 
 
(56,033) 
Net increase (decrease) in cash
 
(4,013)  
2,519 
 
(12,328) 
Cash at beginning of period
 
4,013 
 
1,494 
 
13,822 
Cash at end of period
$ 
— 
$ 
4,013 
$ 
1,494 
Supplemental disclosures of cash flow information (Note 19)
The accompanying notes are an integral part of these consolidated financial statements.
F-9

 EARTHSTONE ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
 
 
Note 1. Organization and Basis of Presentation
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. (“Lynden US”), collectively own a 75.5% interest 
in EEH. The Company consolidates the financial results of EEH and presents a noncontrolling interest in the Consolidated 
Financial Statements representing the economic interests of EEH’s members other than Earthstone and Lynden US. Each of the 
outstanding shares of Class A common stock, $0.001 par value per share of Earthstone (the “Class A Common Stock”), 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 collectively represent the noncontrolling interests in the Consolidated Financial Statements.
At any time, at the holder’s discretion, a holder of an EEH Unit may receive a share of Class A Common Stock in exchange for 
an EEH Unit and a corresponding share of Class B Common Stock, resulting in the immediate cancellation of both the EEH 
Unit and share of Class B Common Stock exchanged. As of December 31, 2022, outstanding common shares of Earthstone, 
along with the equal number of corresponding outstanding EEH Units, were approximately 139.8 million, consisting of 
105.5 million shares of Class A Common Stock and 34.3 million shares of Class B Common Stock.
Note 2. Noncontrolling Interest
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 
Net income in the Consolidated Statements of 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 its subsidiaries, and presents a noncontrolling interest for the economic 
interest in Earthstone held by members of EEH other than Earthstone and Lynden US, and represented by outstanding shares of 
Class B Common Stock. Net income attributable to noncontrolling interest in the Consolidated Statements of Operations for the 
year ended December 31, 2022 represents the portion of net income attributable to the economic interest in the Company held 
by members of EEH other than Earthstone and Lynden US. The noncontrolling interest in the Consolidated Balance Sheet as of 
December 31, 2022 represents the portion of net assets of the Company attributable to members of EEH other than Earthstone 
and Lynden US.
F-10

The following table presents the changes in noncontrolling interest for the year ended December 31, 2022:
 
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 
Note 3. Summary of Significant Accounting Policies
Principles of Consolidation
The 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.
Use of Estimates
The preparation of the Company’s 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 and the reported amounts of 
revenues and expenses during the respective reporting periods then ended.
Estimated quantities of crude oil, natural gas and natural gas liquids reserves are the most significant of the Company’s 
estimates. All reserve data used in the preparation of the Consolidated Financial Statements, as well as included in Note 20. 
Supplemental Information On Oil And Gas Exploration And Production Activities (Unaudited), are based on estimates. 
Reservoir engineering is a subjective process of estimating underground accumulations of crude oil, natural gas and natural gas 
liquids. There are numerous uncertainties inherent in estimating quantities of proved crude oil, natural gas and natural gas 
liquids reserves. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and 
geological interpretation and judgment. As a result, reserve estimates may be different from the quantities of crude oil, natural 
gas and natural gas liquids that are ultimately recovered.
Other items subject to estimates and assumptions include, but are not limited to, the carrying amounts of property, plant and 
equipment, asset retirement obligations, valuation allowances for deferred income tax assets, valuation of derivative instruments 
and valuation of certain performance-based restricted stock unit awards. Management evaluates estimates and assumptions on 
an ongoing basis using historical experience and other factors, including the current economic and commodity price 
environment. The volatility of commodity prices results in increased uncertainty inherent in such estimates and assumptions. 
See Note 20. Supplemental Information On Oil and Gas Exploration and Production Activities (Unaudited).
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
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 
EARTHSTONE ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
F-11

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 $0.02 million and $0.02 million at December 31, 2022 and 2021, respectively. 
Derivative Instruments
The Company utilizes derivative instruments in order to manage exposure to risks associated with fluctuating commodity prices 
and 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.
Oil and Natural Gas Properties
The method of accounting for oil and natural gas properties determines what costs are capitalized and how these costs are 
ultimately matched with revenues and expenses. The Company uses the successful efforts method of accounting for oil and 
natural gas properties. For more information see Note 8. Oil and Natural Gas Properties.
Office and Other Equipment
Office and other equipment primarily includes leasehold improvements, vehicles, computer equipment and software, office 
furniture and fixtures and field equipment. These items are recorded at cost, or fair value if acquired, and are depreciated using 
the straight-line method based on expected lives of the individual assets or group of assets ranging from two years to 10 years. 
The Company had office and other equipment of $5.4 million and $2.0 million, net of accumulated depreciation and 
amortization of $5.3 million and $4.5 million, at December 31, 2022 and 2021, respectively. During the years ended December 
31, 2022, 2021 and 2020, the Company recognized depreciation expense of $1.3 million, $0.7 million and $0.5 million, 
respectively. See separate finance lease disclosures in Note 18. Leases.
Noncontrolling Interest
Noncontrolling Interest represents third-party equity ownership of EEH 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 Net income in the Consolidated 
Statements of Operations for the years ended December 31, 2022 and 2021. As of December 31, 2022, Earthstone and Lynden 
US owned a 75.5% membership interest in EEH while Bold Energy Holdings, LLC (“Bold Holdings”), the noncontrolling 
third-party, or its permitted transferees, owned the remaining 24.5%. See further discussion in Note 2. Noncontrolling Interest.
Segment Reporting
Operating segments are 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 the Company’s organization and management, it has only one reportable operating segment, which is oil and natural 
gas exploration and production. 
Comprehensive Income
The Company has no elements of comprehensive income other than net income.
Asset Retirement Obligations
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 
EARTHSTONE ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
F-12

credit-adjusted risk-free interest rate. Accretion expense is recognized over time as the discounted liabilities are accreted to their 
expected settlement value. If estimated future costs of asset retirement obligations change, an adjustment is recorded to both the 
asset retirement obligations and the long-lived asset. Revisions to estimated asset retirement obligations can result from changes 
in retirement cost estimates, revisions to estimated inflation rates, and changes in the estimated timing of abandonment. For 
further discussion, see Note 13. Asset Retirement Obligations.
Business Combinations
The Company accounts for its acquisitions of oil and gas properties not commonly controlled 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 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 values as of the acquisition date, recording goodwill for amounts paid in excess of fair 
value.
Revenue Recognition
The Company’s revenues are comprised solely of revenues from customers and include the sale of oil, natural gas and natural 
gas 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 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 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 Sales
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. 
Natural Gas and Natural Gas Liquid Sales
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.
Imbalances
EARTHSTONE ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
F-13

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 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 also subject to natural gas pipeline imbalances, which are recorded as accounts receivable 
or payable at values consistent with contractual arrangements with the owner of the pipeline. The Company had no imbalances 
as of December 31, 2022 or 2021.
Contract Balances
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.
Transaction Price Allocated to Remaining Performance Obligations
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.
Prior-Period Performance Obligations
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.
Concentration of Credit Risk
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 the year ended December 31, 2022, three purchasers 
accounted for 21%, 20% and 14%, respectively, of the Company’s oil, natural gas, and natural gas liquids revenues. In the year 
ended December 31, 2021, two purchasers accounted for 34% and 13%, respectively, of the Company’s oil, natural gas, and 
natural gas liquids revenues. In the year ended December 31, 2020, three purchasers accounted for 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 the years ended December 31, 2022, 2021 or 
2020. Additionally, at December 31, 2022, four purchasers accounted for 21%, 19% , 18% and 14%, respectively, of the 
Company’s oil, natural gas and natural gas liquids receivables. At December 31, 2021, three purchasers accounted for 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, 2022 and 
2021.
The Company holds working interests in oil and natural gas properties for which a third-party serves as operator. The operator 
sells the oil, natural gas, and natural gas liquids to the purchaser, collects the cash, and distributes the cash to the Company. In 
the year ended December 31, 2022, one operator distributed 8% of the Company’s oil, natural gas and natural gas liquids 
revenues. In the year ended December 31, 2021 one operator distributed 13% of the Company’s oil, natural gas and natural gas 
liquids revenues. In the year ended December 31, 2020, one operator distributed 15% of the Company’s oil, natural gas and 
natural gas liquids revenues.
EARTHSTONE ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
F-14

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, 2022, the 
Company had a net derivative asset position of $26.4 million. At December 31, 2021, the Company had a 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.
Stock-Based Compensation
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 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. See Note 11. Stock-Based Compensation for further details.
Income Taxes
The Company is a U.S. company operating in Texas and New Mexico, as of December 31, 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, 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.
The Company 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. 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.
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, 2022 and 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. It requires that the Company 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. 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, 
2022 or 2021.
Recently Issued Accounting Standards
Reference Rate Reform - In March 2020, the FASB issued an update that provides optional guidance for a limited period of time 
to ease the transition from LIBOR to an alternative reference rate. The ASU intends to address certain concerns relating to 
EARTHSTONE ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
F-15

accounting for contract modifications and hedge accounting. The Company amended its credit facility on January 30, 2022, 
which, among other things, provided mechanics relating to the transition from LIBOR to a benchmark replacement rate. The 
transition from LIBOR did not have a material impact on the Company’s consolidated financial statements.
Note 4. Acquisitions and Divestitures
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.
Titus Acquisition
On June 27, 2022, Earthstone and EEH, as buyer, and Titus Oil & Gas Production, LLC, a Delaware limited liability company, 
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, entered into a purchase and sale 
agreement (the “Titus I Purchase Agreement”) which provided that EEH or its designated wholly-owned subsidiary would 
acquire (the “Titus I Acquisition”) interests in oil and gas leases and related property of Titus I located in the Northern 
Delaware Basin of New Mexico (the “Titus I Assets”). Also on June 27, 2022, Earthstone and EEH, as buyer, and Titus Oil & 
Gas Production II, LLC, a Delaware limited liability company, Lenox Minerals II, LLC, a Delaware limited liability company 
and Lenox Mineral Holdings II, Inc., a Delaware limited liability company (collectively, “Titus II” and together with Titus I, 
“Titus”), as seller, entered into a purchase and sale agreement (the “Titus II Purchase Agreement” and together with the Titus I 
Purchase Agreement, the “Titus Purchase Agreements”) which provided that EEH or its designated wholly-owned subsidiary 
would acquire (the “Titus II Acquisition” and together with the Titus I Acquisition, the “Titus Acquisition”) interests in oil and 
gas leases and related property of Titus II located in the Northern Delaware Basin of New Mexico (the “Titus II Assets” and 
together with the Titus I Assets, the “Titus Assets”).
On August 10, 2022, the transactions contemplated in the Titus Purchase Agreements were consummated whereby EEH 
acquired the Titus Assets for aggregate consideration of approximately $567.7 million in cash, net of customary purchase price 
adjustments, and 3,857,015 shares of Class A Common Stock.
The Titus Acquisition was accounted for as an asset acquisition. The fair value of the consideration paid by us and allocation of 
that amount to the underlying assets acquired, on a relative fair value basis, was recorded on our books as of the date of the 
closing of the Titus Acquisition. Additionally, costs directly related to the Titus Acquisition were capitalized as a component of 
the purchase price. The consideration transferred, fair value of assets acquired and liabilities assumed by the Company were 
recorded as follows (in thousands, except share amounts and stock price):
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 
(1)
Represents $1.1 million of transaction costs associated with the Titus Acquisition which have been capitalized in accordance with ASC 805-50.
Bighorn Acquisition 
On January 30, 2022, Earthstone, EEH, as buyer, and Bighorn Asset Company, LLC, a Delaware limited liability company 
(“Bighorn”), as seller, entered into a purchase and sale agreement (the “Bighorn Agreement”). Pursuant to the Bighorn 
EARTHSTONE ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
F-16

Agreement, EEH acquired (the “Bighorn Acquisition”) interests in oil and gas leases and related property of Bighorn located in 
the Midland Basin, Texas (the “Bighorn Assets”).
On April 14, 2022, Earthstone, EEH and Bighorn consummated the transactions contemplated in the Bighorn Agreement 
whereby EEH acquired the Bighorn Assets for aggregate consideration of approximately $628.2 million in cash, net of 
customary purchase price adjustments, and 5,650,977 shares of Class A Common Stock. 
The Bighorn Acquisition was accounted for as an asset acquisition. The fair value of the consideration paid by us and allocation 
of that amount to the underlying assets acquired, on a relative fair value basis, was recorded on our books as of the date of the 
closing of the Bighorn Acquisition. Additionally, costs directly related to the Bighorn Acquisition were capitalized as a 
component of the purchase price. The consideration transferred, fair value of assets acquired and liabilities assumed by the 
Company were recorded as follows (in thousands, except share amounts and stock price):
Consideration:
Shares of Class A Common Stock issued
 
5,650,977 
Class A Common Stock price as of April 14, 2022
$ 
13.76 
Class A Common Stock consideration
 
77,757 
Cash consideration
 
625,842 
Direct transaction costs (1)
 
2,347 
Total consideration transferred
$ 
705,946 
Fair value of assets acquired:
Current assets
$ 
769 
Oil and gas properties
 
746,116 
Amount attributable to assets acquired
$ 
746,885 
Fair value of liabilities assumed:
Suspense payable
 
25,710 
Other current liabilities
 
2,035 
Noncurrent liabilities - ARO
 
13,194 
Amount attributable to liabilities assumed
$ 
40,939 
(1)
Represents $2.4 million of transaction costs associated with the Bighorn Acquisition which have been capitalized in accordance with ASC 805-50.
Chisholm Acquisition
As part of the execution of its growth strategy to further increase its scale, on December 15, 2021, Earthstone, EEH, as buyer, 
Chisholm Energy Operating, LLC (“OpCo”) and Chisholm Energy Agent, Inc. (“Agent” and collectively with OpCo, 
“Chisholm”), collectively as seller, entered into a Purchase and Sale Agreement (the “Chisholm Agreement”), which provided 
that EEH would acquire (the “Chisholm Acquisition”) interests in oil and gas leases and related property of Chisholm located in 
Lea County and Eddy County, New Mexico (the “Chisholm Assets”).
On February 15, 2022, Earthstone, EEH and Chisholm consummated the transactions contemplated in the Chisholm Agreement 
whereby EEH acquired the Chisholm Assets for aggregate consideration consisting of: (i) approximately $314.0 million in cash, 
net of customary purchase price adjustments, 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. The fair value of each share of Class A Common Stock 
was determined using the closing sales price of $12.85 per share on February 15, 2022. A Significant Shareholder, as identified 
below, was the majority owner of Chisholm as of the closing of the Chisholm Acquisition. See Note 14. Related Party 
Transactions, for further discussion.
EARTHSTONE ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
F-17

The Chisholm Acquisition has been accounted for as a business combination using the acquisition method of accounting, with 
Earthstone identified as the acquirer. The consideration transferred, fair value of assets acquired and liabilities assumed by 
Earthstone were recorded as follows (in thousands, except share amounts and stock price):
Consideration:
Shares of Class A Common Stock issued
 
19,417,476 
Class A Common Stock price as of February 15, 2022
$ 
12.85 
Class A Common Stock consideration
 
249,515 
Cash consideration
 
383,976 
Total consideration transferred
$ 
633,491 
Fair value of assets acquired:
Oil and gas properties
$ 
642,485 
Amount attributable to assets acquired
$ 
642,485 
Fair value of liabilities assumed:
Other current liabilities
$ 
3,023 
Asset retirement obligation - noncurrent
 
5,971 
Amount attributable to liabilities assumed
$ 
8,994 
IRM Acquisition
As part of the execution of its growth strategy to further increase its scale, on January 7, 2021, the Company completed the 
acquisition (the “IRM Acquisition”) of all of the issued and outstanding limited liability company interests in Independence 
Resources Management, LLC (“IRM”) and certain wholly owned subsidiaries for consideration consisting of (i) net cash of 
approximately $140.5 million and (ii) 12,719,594 shares of Class A Common Stock. The fair value of each share of Class A 
Common Stock was determined using the closing price of $6.02 per share on January 7, 2021. The purchase agreement 
contained customary representations and warranties for transactions of this nature. The Company obtained representation and 
warranty insurance to provide coverage in the event of certain breaches of representations and warranties of the seller contained 
in the purchase agreement, which are subject to various exclusions, deductibles and other terms and conditions set forth therein.
EARTHSTONE ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
F-18

The IRM Acquisition was accounted for as a business combination using the acquisition method of accounting, with Earthstone 
identified as the acquirer. The consideration transferred, fair value of assets acquired and liabilities assumed by Earthstone were 
recorded as follows (in thousands, except share amounts and stock price):
Consideration:
Shares of Class A Common Stock issued
 
12,719,594 
Class A Common Stock price as of January 7, 2021
$ 
6.02 
Class A Common Stock consideration
 
76,572 
Cash consideration
 
140,507 
Total consideration transferred
$ 
217,079 
Fair value of assets acquired:
Cash
$ 
4,763 
Other current assets
 
11,524 
Oil and gas properties
 
224,112 
Other non-current assets
 
252 
Amount attributable to assets acquired
$ 
240,651 
Fair value of liabilities assumed:
Derivative liability
$ 
10,177 
Other current liabilities
 
5,196 
Asset retirement obligation - noncurrent
 
8,199 
Amount attributable to liabilities assumed
$ 
23,572 
Tracker/Sequel Acquisitions
On March 31, 2021, Earthstone, EEH, Tracker Resource Development III, LLC, a Delaware limited liability company 
(“Tracker Opco”), and TRD III Royalty Holdings (TX), LP, a Delaware limited partnership (“RoyaltyCo” and collectively with 
Tracker Opco, “Tracker”), entered into a purchase and sale agreement (the “Tracker Agreement”), which provided that EEH 
would acquire (the “Tracker Acquisition”) interests in oil and gas leases and related property of Tracker located in Irion 
County, Texas (the “Tracker Assets”). Also on March 31, 2021, Earthstone, EEH, SEG-TRD LLC, a Delaware limited liability 
company (“SEG-I”), and SEG-TRD II LLC, a Delaware limited liability company (“SEG-II” and collectively with SEG-I, 
“Sequel”) entered into a purchase and sale agreement (the “Sequel Agreement” and collectively with the Tracker Agreement, 
the “Tracker/Sequel Purchase Agreements”), which provided that EEH would acquire (the “Sequel Acquisition” and 
collectively with the Tracker Acquisition, the “Tracker/Sequel Acquisitions”) certain well-bore interests and related equipment 
(the “Sequel Assets”).
On July 20, 2021, Earthstone, EEH and Tracker consummated the transactions contemplated in the Tracker Agreement. At the 
closing of the Tracker Agreement, among other things, EEH acquired the Tracker Assets for aggregate consideration consisting 
of: (i) $18.8 million in cash, net of customary purchase price adjustments, and (ii) 4.7 million shares of Class A Common Stock. 
Also, on July 20, 2021, Earthstone, EEH and Sequel consummated the transactions contemplated in the Sequel Agreement. At 
the closing of the Sequel Agreement, among other things, EEH acquired the Sequel Assets for aggregate consideration 
consisting of: (i) $41.4 million in cash, net of customary purchase price adjustments, and (ii) 1.5 million shares of Class A 
Common Stock. The Significant Shareholder, as described in the Note referenced below, owned approximately 49% of Tracker 
as of the closing of the Tracker Acquisition. See Note 14. Related Party Transactions, for further discussion.
EARTHSTONE ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
F-19

In accordance with ASC Topic 805, Business Combinations (referred to as “ASC 805”), the Tracker/Sequel Acquisitions have 
been accounted for as asset acquisitions. The consideration transferred, fair value of assets acquired and liabilities assumed by 
Earthstone were recorded as follows (in thousands, except share amounts and stock price):
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 
(1)
Includes customary purchase price adjustments.
(2)
Represents $1.7 million of transaction costs associated with the Tracker Acquisition and the Sequel Acquisition that have been capitalized in 
accordance with ASC 805-50.
The following unaudited supplemental pro forma condensed results of operations present consolidated information as though 
the Chisholm Acquisition and IRM Acquisition had been completed as of January 1, 2021. The unaudited supplemental pro 
forma financial information was derived from the historical consolidated and combined statements of operations for Chisholm, 
IRM and Earthstone and adjusted to include depletion expense applied to the adjusted basis of the properties acquired. 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 Company for the periods presented or that may be 
achieved by the Company in the future. Future results may vary significantly from the results reflected in this unaudited pro 
forma financial information (in thousands, except per share amounts):
 
Years Ended December 31,
 
2022
2021
Revenue
$ 
1,731,159 $ 
637,803 
Income (loss) before taxes
 
795,447  
(63,479) 
Net income (loss)
 
671,031  
(65,339) 
Less: Net income (loss) attributable to noncontrolling interest
 
204,349  
(27,644) 
Net income (loss) attributable to Earthstone Energy, Inc.
 
466,682  
(37,695) 
Pro forma net income (loss) per common share attributable to Earthstone Energy, Inc.:
Basic
$ 
5.14 $ 
(0.56) 
Diluted
$ 
4.85 $ 
(0.54) 
The Company has included in its Consolidated Statements of Operations, revenues of $300.0 million and operating expenses of 
$131.5 million for the period from February 15, 2022 to December 31, 2022 related to the Chisholm Acquisition. During the 
year ended December 31, 2022, the Company recorded $10.7 million of legal and professional fees related to the Chisholm 
Acquisition which are included in Transaction costs in the Consolidated Statements of Operations.
The fair value measurements of assets acquired and liabilities assumed are based on inputs that are not observable in the market 
and therefore represent Level 3 inputs. The fair value of oil and gas properties and asset retirement obligations were measured 
using the discounted cash flow technique of valuation.
Significant inputs to the valuation of oil and gas properties include estimates of: (i) reserves, (ii) future operating and 
development costs, (iii) future commodity prices, (iv) future plugging and abandonment costs, (v) estimated future cash flows, 
EARTHSTONE ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
F-20

and (vi) a market-based weighted average cost of capital rate. These inputs require significant judgments and estimates and are 
the most sensitive and subject to change.
Eagle Ford Acquisitions
In May and June 2021, the Company completed acquisitions of working interests in certain assets it operates located in southern 
Gonzales County, Texas (collectively, the “Eagle Ford Acquisitions”) from four separate sellers. The aggregate purchase price 
of the Eagle Ford Acquisitions was approximately $45.2 million. One of the four separate sellers was a related party. See Note 
14. Related Party Transactions for further discussion. The Eagle Ford Acquisitions have been accounted for as asset 
acquisitions in accordance with ASC 805. The preliminary allocation of each purchase was based upon management’s estimates 
of and assumptions related to the relative fair value of assets acquired and liabilities assumed.
Foreland-BCC Acquisition
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.
Divestitures
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.
Note 5. Transaction Costs
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.
Note 6. Fair Value Measurements
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:
EARTHSTONE ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
F-21

Level 1 – Unadjusted, quoted prices in active markets that are accessible at the measurement date for identical, unrestricted 
assets or liabilities. An active market is defined as a market where transactions for the financial instrument occur with sufficient 
frequency and volume to provide pricing information on an ongoing basis.
Level 2 – Inputs, other than quoted prices within Level 1, that are either directly or indirectly observable for the asset or 
liability through correlation with market data at the measurement date and for the duration of the instrument’s anticipated life.
Level 3 – Prices or valuations that require unobservable inputs that are both significant to the fair value measurement and 
unobservable. Valuation under Level 3 generally involves a significant degree of judgment from management.
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 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, 2022.
Fair Value on a Recurring Basis
Derivative Financial Instruments
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 and 
interest rate swaps. The Company’s commodity price hedges and interest rate swaps are valued based on discounted future cash 
flow models that are primarily based on published forward commodity price curves and published LIBOR forward curves; thus, 
these inputs are designated as Level 2 within the valuation hierarchy.
The fair values of derivative instruments in asset positions include measures of counterparty nonperformance risk, and the fair 
values of derivative instruments in liability positions include measures of the Company’s nonperformance risk. These 
measurements were not material to the Consolidated Financial Statements.
Share-based Compensation Liability
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.
EARTHSTONE ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
F-22

The following table summarizes the fair value of the Company’s financial assets and liabilities, by level within the fair-value 
hierarchy (in thousands): 
December 31, 2022
Level 1
Level 2
Level 3
Total
Financial assets
 
 
 
 
Derivative asset- current
$ 
— $ 
31,331 $ 
— $ 
31,331 
Derivative asset- noncurrent
 
—  
9,117  
—  
9,117 
Total financial assets
$ 
— $ 
40,448 $ 
— $ 
40,448 
Financial liabilities
Derivative liability - current
$ 
— $ 
14,053 $ 
— $ 
14,053 
Share-based compensation liability - current
 
—  
14,411  
—  
14,411 
Share-based compensation liability - noncurrent
 
—  
10,357  
—  
10,357 
Total financial liabilities
$ 
— $ 
38,821 $ 
— $ 
38,821 
December 31, 2021
Financial assets
 
 
 
 
Derivative asset- current
$ 
— $ 
1,348 $ 
— $ 
1,348 
Derivative asset- noncurrent
 
—  
157  
—  
157 
Total financial assets
$ 
— $ 
1,505 $ 
— $ 
1,505 
Financial liabilities
Derivative liability - current
$ 
— $ 
45,310 $ 
— $ 
45,310 
Derivative liability - noncurrent
 
—  
571  
—  
571 
Share-based compensation liability - current
 
—  
7,835  
—  
7,835 
Share-based compensation liability - noncurrent
 
—  
6,324  
—  
6,324 
Total financial liabilities
$ 
— $ 
60,040 $ 
— $ 
60,040 
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.
Fair Value on a Nonrecurring Basis
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 asset retirement obligations. These assets 
and liabilities are not measured at fair value on an ongoing basis but are subject to fair value adjustments if events or changes in 
certain circumstances indicate that adjustments may be necessary. Due to significant declines in commodity prices and 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 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. 
Items Not Recorded at Fair Value
The carrying amounts reported on the unaudited consolidated balance sheets for cash, accounts receivable, prepaid expenses, 
other current assets accounts payable, revenues and royalties payable, accrued expenses and other current liabilities 
approximate their fair values. 
The Company has not elected to account for its debt instruments at fair value. Borrowings under the revolving tranche and term 
loan tranche of the Company’s credit facility bear interest at floating market rates, therefore the carrying amounts and fair 
values were approximately equal as of December 31, 2022 and December 31, 2021. The carrying value of EEH’s 8.000% 
Senior Notes due 2027, net of $10.9 million deferred financing costs, of $539.1 million and accrued interest of $9.5 million had 
an estimated fair value of $530.3 million. There were no other debt instruments outstanding at December 31, 2022. 
EARTHSTONE ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
F-23

Note 7. Derivative Financial Instruments
Commodity Derivative Instruments
The Company’s hedging activities primarily 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, 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. 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 premium is not paid until the expiration of the option. Consistent with its hedging policy, the 
Company has entered into a series of derivative instruments to hedge a portion of its expected oil and natural gas production 
through December 31, 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, the Company believes these instruments 
reduce its exposure to oil and natural gas price fluctuations and, thereby, allow the Company to achieve a more predictable cash 
flow. The Company does not enter into derivative instruments for trading or other speculative purposes.
The Company’s derivative instruments are cash flow hedge transactions in which it is hedging the variability of cash flow 
related to a forecasted transaction. The Company does not enter into derivative instruments for trading or other speculative 
purposes. These transactions are recorded in the Consolidated Financial Statements in accordance with FASB ASC Topic 815. 
The Company has accounted for these transactions using the mark-to-market accounting method. Generally, the Company 
incurs accounting losses on derivatives during periods where prices are rising and gains during periods where prices are falling 
which may cause significant fluctuations in the Consolidated Balance Sheets and Consolidated Statements of Operations.
The Company nets its derivative instrument fair value amounts executed with each counterparty pursuant to an International 
Swap Dealers Association Master Agreement (“ISDA”), which provides for net settlement over the term of the contract. The 
ISDA is a standard contract that governs all derivative contracts entered into between the Company and the respective 
counterparty. The ISDA allows for offsetting of amounts payable or receivable between the Company and the counterparty, at 
the election of both parties, for transactions that occur on the same date and in the same currency.
The following table sets forth the Company’s outstanding derivative contracts at December 31, 2022. When aggregating 
multiple contracts, the weighted average contract price is disclosed.
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 WTI Midland Argus Crude and the WTI NYMEX.
(2)
The basis differential price is between W. Texas (WAHA) and the Henry Hub NYMEX.
 
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 
EARTHSTONE ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
F-24

Interest Rate Swaps
At times, the Company’s hedging activities include the use of interest rate swaps entered into in order to manage cash flow 
variability resulting from changes in interest rates. These derivative instruments are not accounted for under hedge accounting.
In December 2021, the Company unwound its interest rate swap contracts, receiving a one-time settlement payment of 
$1.1 million. The Company had no interest rate swaps in place as of December 31, 2022 or 2021.
The following table summarizes the location and fair value amounts of all derivative instruments in the Consolidated Balance 
Sheets as well as the gross recognized derivative assets, liabilities, and amounts offset in the Consolidated Balance Sheets (in 
thousands): 
 
 
December 31, 2022
December 31, 2021
Derivatives not
designated as hedging
contracts under ASC
Topic 815
Balance Sheet Location
Gross
Recognized
Assets /
Liabilities
Gross
Amounts
Offset
Net
Recognized
Assets /
Liabilities
Gross
Recognized
Assets /
Liabilities
Gross
Amounts
Offset
Net
Recognized
Assets /
Liabilities
Commodity contracts
Derivative asset - current
$ 51,803 $ (20,472) $ 31,331 $ 
3,191 $ (1,843) $ 
1,348 
Commodity contracts
Derivative liability - 
current
$ 34,525 $ (20,472) $ 14,053 $ 47,153 $ (1,843) $ 45,310 
Commodity contracts
Derivative asset - 
noncurrent
$ 
9,117 $ 
— $ 
9,117 $ 
2,721 $ (2,564) $ 
157 
Commodity contracts
Derivative liability - 
noncurrent
$ 
— $ 
— $ 
— $ 
3,135 $ (2,564) $ 
571 
 
The follow table summarizes the location and amounts of the Company’s realized and unrealized gains and losses on 
derivatives instruments in the Company’s Consolidated Statements of Operations and Consolidated Statements of Cash Flows 
(in thousands): 
Derivatives not designated as hedging contracts under ASC Topic 815
Years Ended December 31,
Statement of Cash Flows Location
Statement of Operations Location
2022
2021
2020
Unrealized gain 
(loss)
Not presented separately
Not presented separately
$ 
70,769 $ 
(40,795) $ 
3,855 
Realized (loss) 
gain
Operating portion of net cash 
received in settlement of 
derivative contracts
Not presented separately
 
(195,876)  
(75,966)  
56,044 
Total loss (gain) on 
derivative contracts, net
(Loss) gain on derivative 
contracts, net
$ (125,107) $ (116,761) $ 
59,899 
Note 8. Oil and Natural Gas Properties
The Company follows the successful efforts method of accounting for its oil and natural gas properties. Under this method, 
costs to acquire oil and natural gas properties, drill and equip exploratory wells that find proved reserves, and drill and equip 
development wells are capitalized. Exploration costs, including unsuccessful exploratory wells and geological and geophysical 
costs, are charged to operations as incurred. Upon sale or retirement of oil and natural gas properties, the costs and related 
accumulated depreciation, depletion and amortization are eliminated from the accounts and the resulting gain or loss is 
recognized.
Costs incurred to maintain wells and related equipment, lease and well operating costs, and other exploration costs are charged 
to expense as incurred. Gains and losses arising from the sale of properties are included in operating income in the Consolidated 
Statements of Operations.
The Company’s lease acquisition costs and development costs of proved oil and natural gas properties are amortized using the 
units-of-production method, at the field level, based on total proved reserves and proved developed reserves, respectively. 
Depletion expense for oil and natural gas producing property and related equipment was $300.5 million, $105.7 million and 
$95.9 million for the years ended December 31, 2022, 2021 and 2020, respectively.
Proved Oil and Natural Gas Properties
Proved oil and natural gas properties are reviewed for impairment on a nonrecurring basis. The impairment charge reduces the 
carrying values to their estimated fair values. These fair value measurements are classified as Level 3 measurements and 
include many unobservable inputs. Fair value is calculated as the estimated discounted future net cash flows attributable to the 
assets. The Company’s primary assumptions in preparing the estimated discounted future net cash flows to be recovered from 
EARTHSTONE ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
F-25

oil and natural gas properties are based on (i) proved reserves, (ii) forward commodity prices and assumptions as to costs and 
expenses, and (iii) the estimated discount rate that would be used by potential purchasers to determine the fair value of the 
assets.
Unproved Oil and Natural Gas Properties
Unproved properties consist of costs incurred to acquire undeveloped leases as well as the cost to acquire unproved reserves. 
Undeveloped lease costs and unproved reserve acquisition costs are capitalized. Unproved oil and natural gas leases are 
generally for a primary term of three to five years. In most cases, the term of the unproved leases can be extended by paying 
delay rentals, meeting contractual drilling obligations, or by the presence of producing wells on the leases. Unproved costs 
related to successful exploratory drilling are reclassified to proved properties and depleted on a units-of-production basis.
The Company reviews its unproved properties periodically for impairment. In determining whether an unproved property is 
impaired, the Company considers numerous factors including, but not limited to, current exploration and development plans, 
favorable or unfavorable exploration activity on the property being evaluated and/or adjacent properties, the Company’s 
geologists’ evaluation of the property, and the remaining months in the lease term for the property.
Impairments to Oil and Natural Gas Properties
The Company recorded no non-cash asset impairment charges for the years ended December 31, 2022 or 2021. 
During the year ended December 31, 2020, primarily as a result of the decline in crude oil price futures, the Company recorded 
non-cash impairment charges of $25.3 million to its proved oil and natural gas properties and $13.2 million to its unproved oil 
and natural gas properties, located in the Eagle Ford Trend. As a result of certain acreage expirations, the Company recorded 
non-cash impairment charges of $8.4 million to its unproved oil and natural gas properties during the year ended December 31, 
2020.
Accumulated impairments to proved and unproved oil and natural gas properties as of December 31, 2022 and 2021 were 
$168.0 million and $168.0 million, respectively.
Note 9. Net Income (Loss) Per Common Share
Net income (loss) per common share—basic is calculated by dividing Net income (loss) by the weighted average number of 
shares of common stock outstanding during the period. Net income (loss) per common share—diluted assumes the conversion 
of all potentially dilutive securities and is calculated by dividing Net income (loss) by the sum of the weighted average number 
of shares of common stock, as defined above, outstanding plus potentially dilutive securities. Net income (loss) per common 
share—diluted considers the impact of potentially dilutive securities except in periods in which there is a loss because the 
inclusion of the potential common shares, as defined above, would have an anti-dilutive effect. 
EARTHSTONE ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
F-26

A reconciliation of Net income (loss) per common share is as follows:
 
Years Ended December 31,
(In thousands, except per share amounts)
2022
2021
2020
Net income (loss) attributable to Earthstone Energy, Inc.
$ 
452,485 $ 
35,484 $ 
(13,547) 
Net income (loss) attributable to Earthstone Energy, Inc. from assumed 
conversion of Series A Convertible Preferred Stock (1)
 
12,388  
—  
— 
Net income (loss) attributable to Earthstone Energy, Inc. - Diluted
 
464,873  
35,484  
(13,547) 
Net income (loss) per common share attributable to Earthstone Energy, 
Inc.:
Basic
$ 
5.12 $ 
0.75 $ 
(0.45) 
Diluted
$ 
4.83 $ 
0.71 $ 
(0.45) 
Weighted average common shares outstanding
Basic
 
88,349,088  
47,169,948  
29,911,625 
Add potentially dilutive securities:
Unvested restricted stock units
 
416,031  
539,803  
— 
Unvested performance units
 
1,757,841  
2,242,342  
— 
Series A Convertible Preferred Stock(1)
 
5,805,257  
—  
— 
Diluted weighted average common shares outstanding
 
96,328,217  
49,952,093  
29,911,625 
(1)
On April 14, 2022, Earthstone issued 280,000 shares of Series A Convertible Preferred Stock which automatically converted into 25,225,225 shares 
of Class A Common Stock on July 6, 2022. Under the “If-Converted” method, the shares would have been assumed issued on April 14, 2022, which 
would have resulted in an additional allocation of Net income (loss) attributable to Earthstone Energy, Inc. of $12.4 million for the year ended 
December 31, 2022.
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 $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 income (loss) attributable to 
Earthstone Energy, Inc. for the years then ended, having no dilutive effect on Net income (loss) per common share attributable 
to Earthstone Energy, Inc. For the year ended December 31, 2020, the Company excluded 1.1 million and 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 for the period.
Note 10. Common Stock and Preferred Stock
Class A Common Stock
At December 31, 2022 and 2021, there were 105,547,139 and 53,467,307 shares of Class A Common Stock issued and 
outstanding, respectively. During the year ended December 31, 2022, Earthstone issued a total of approximately 28.9 million 
shares of Class A Common 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 year ended December 31, 2021, Earthstone issued 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 Long-Term Incentive Plan, as amended (the “2014 Plan”), Earthstone issued 1,273,795, 1,381,825 and 914,905 shares of 
Class A Common Stock, respectively, of which 429,547, 453,483 and 243,924 shares of Class A Common Stock, respectively, 
were retained as treasury stock and cancelled to satisfy the related employee income tax liability.
On October 11, 2022, Earthstone purchased and immediately cancelled 3,000,000 shares of Class A Common Stock from 
certain affiliates of Warburg Pincus LLC (“Warburg”) in a private transaction, for an aggregate purchase price of $43,740,000, 
or $14.58 per share. 
EARTHSTONE ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
F-27

Class B Common Stock
At December 31, 2022 and 2021, there were 34,259,641 and 34,344,532 shares of Class B Common Stock issued and 
outstanding, respectively. Each share of Class B Common Stock, together with one EEH Unit, is convertible into one share of 
Class A Common Stock. During the years ended December 31, 2022, 2021 and 2020, 84,891, 664,839 and 251,309 shares, 
respectively, of Class B Common Stock and EEH Units were exchanged for an equal number of shares of Class A Common 
Stock. 
Series A Convertible Preferred Stock
On January 30, 2022, Earthstone entered into a securities purchase agreement (the “SPA”) with EnCap Energy Capital Fund XI, 
L.P. (“EnCap Fund XI”), an affiliate of EnCap Investments L.P. (“EnCap”), and Cypress Investments, LLC, a fund managed by 
Post Oak Energy Capital, LP (“Post Oak” and collectively with EnCap Fund XI, the “Investors”) to sell, in a private placement 
(the “Private Placement”), 280,000 shares of newly authorized convertible preferred stock, $0.001 par value per share (the 
“Series A Convertible Preferred Stock”), each share of which would be convertible into 90.0900900900901 shares of Class A 
Common Stock for anticipated gross proceeds of $280.0 million, at a price of $1,000.00 per share of Series A Convertible 
Preferred Stock (or $11.10 per share of Class A Common Stock on an as-converted basis). The Private Placement was 
contingent upon the closing of the Bighorn Acquisition. The Company used the net proceeds from the sale of the Series A 
Convertible Preferred Stock to partially fund the Bighorn Acquisition. See Note 14. Related Party Transactions for further 
discussion.
On April 14, 2022, Earthstone, EnCap Fund XI and Cypress consummated the sale and issuance of 280,000 shares of Series A 
Convertible Preferred Stock pursuant to the SPA in exchange for cash proceeds of $279.3 million, net of offering costs.
On July 6, 2022, 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 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.
At December 31, 2022 and 2021, there were no shares of Series A Convertible Preferred Stock issued or outstanding. 
Note 11. Stock-Based Compensation
Restricted Stock Units
The 2014 Plan allows, among other things, for the grant of restricted stock units (“RSUs”). As of December 31, 2022, the 
maximum number of shares of Class A Common Stock that may be issued under the 2014 Plan was 12.0 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. The Company 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, 2022:
 
Shares
Weighted-Average 
Grant Date Fair Value
Unvested RSUs at December 31, 2021
 
771,817 $ 
5.91 
Granted
 
780,765 $ 
13.65 
Forfeited
 
(16,934) $ 
8.17 
Vested
 
(665,670) $ 
7.75 
Unvested RSUs at December 31, 2022
 
869,978 $ 
11.40 
During the year ended December 31, 2022, Earthstone granted 727,765 RSUs to employees and 53,000 RSUs to certain 
members of the Board with vesting periods ranging from 12 to 36 months. The total grant date fair value of the RSUs granted 
during the years ended December 31, 2022, 2021 and 2020 were $10.7 million, $4.1 million and $4.4 million, respectively, with 
a weighted average grant date fair value per share of $13.65, $6.16 and 5.07, respectively. The total vesting date fair value of 
the RSUs that vested during 2022, 2021 and 2020 was $8.9 million, $8.8 million and $3.0 million, respectively. As of 
EARTHSTONE ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
F-28

December 31, 2022, there was approximately $9.2 million of total unrecognized stock-based compensation expense related to 
unvested RSUs, which will be amortized over the remaining vesting periods. The weighted average remaining vesting period of 
the unrecognized compensation expense is 1.20 years.
For the years ended December 31, 2022, 2021 and 2020, stock-based compensation related to RSUs was $6.0 million, $5.2 
million and $5.4 million, respectively. 
Performance Units
The table below summarizes performance unit (“PSU”) activity for the year ended December 31, 2022:
 
Shares
Weighted-Average 
Grant Date Fair Value
Unvested PSUs at December 31, 2021
 
2,751,725 $ 
8.42 
Granted
 
472,485 $ 
19.42 
Vested
 
(608,125) $ 
9.30 
Unvested PSUs at December 31, 2022
 
2,616,085 $ 
10.21 
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 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 Balance Sheets as of December 31, 2022 and 2021, 
respectively. Additionally, corresponding liabilities of $10.4 million and $6.3 million related to the PSUs were included in 
Other noncurrent liabilities in the Consolidated Balance 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: 
Earthstone’s Annualized TSR
TSR Multiplier
23.9% or greater 
2.0
14.5%
1.0
8.4%
0.5
Less than 8.4%
0.0
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. 
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 2022 PSUs, assuming a risk-free rate of 1.4% and volatility of 86.0%, the Company calculated the weighted 
average grant date fair value per PSU to be $19.42.
TSR for the Company and each of the peer companies is generally determined by dividing (A) the volume weighted average 
price of a share of stock for the trading days during the thirty calendar days ending on and including the last calendar day of the 
applicable performance period minus the volume weighted average price of a share of stock for the trading days during the 
thirty calendar days ending on and including the first day of the applicable performance period plus cash dividends paid over 
F-29

the applicable performance period by (B) the volume weighted average price of a share of stock for the trading days during the 
thirty calendar days ending on and including the first day of the applicable performance period.
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: 
Earthstone’s Annualized TSR
TSR Multiplier
20.5% or greater 
2.0
14.5%
1.0
7.7%
0.5
Less than 7.7%
0.0
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:
Earthstone’s Annualized TSR
TSR Multiplier
23.9% or greater 
2.0
14.5%
1.0
8.4%
0.5
Less than 8.4%
0.0
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.
F-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.
Modification of Performance Units
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.
Note 12. Long-Term Debt 
The Company's long-term debt consisted of the following (in thousands):
December 31, 2022
December 31, 2021
Revolving credit facility(1)
$ 
270,136 
$ 
320,000 
Term loan under credit facility due 2027
 
250,000 
 
— 
8.000% Senior notes due 2027
 
550,000 
 
— 
 
1,070,136 
 
320,000 
Unamortized debt issuance costs on term loan
 
(5,309)  
— 
Unamortized debt issuance costs on 8.000% Senior notes
 
(10,948)  
— 
Long-term debt, net
$ 
1,053,879 
$ 
320,000 
(1)
Related to the revolving credit facility borrowings, the Company had debt issuance costs of $15.3 million and $6.7 million, net of accumulated 
amortization of $6.5 million and $3.3 million, as of December 31, 2022 and 2021, respectively. Unamortized deferred financing costs on the 
revolving credit facility borrowings are included in Other noncurrent assets in the Consolidated Balance Sheets.
Credit Agreement
On November 21, 2019, Earthstone, EEH (the “Borrower”), Wells Fargo Bank, National Association, as Administrative Agent 
and Issuing Bank (“Wells Fargo”), BOKF, NA dba Bank of Texas, as Issuing Bank with respect to Existing Letters of Credit, 
Royal Bank of Canada, as Syndication Agent, Truist Bank, as successor by merger to SunTrust Bank, as Documentation Agent, 
and the Lenders party thereto (collectively, the “Parties”) entered into a credit agreement (the “Credit Agreement”), which 
replaced the prior credit facility, which was terminated on November 21, 2019.
On January 30, 2022, Earthstone, EEH, as Borrower, Wells Fargo as Administrative Agent, the lenders party thereto (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, 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 to 
$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 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 August 10, 2022, Earthstone, EEH, Wells Fargo as Administrative Agent, the Lenders and the guarantors party thereto 
entered into an amendment (the “Seventh Amendment”) to the Credit Agreement. Among other things, the Seventh 
F-31

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 interest rate of Term SOFR (as 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 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 September 29, 2022, in connection with a regularly scheduled borrowing base redetermination, the borrowing base 
increased from $1.7 billion to $1.85 billion.
The next regularly scheduled redetermination of the borrowing base is expected to occur on or around May 1, 2023. Subsequent 
redeterminations are expected to occur on or about each November 1st and May 1st thereafter. The amounts borrowed under the 
Credit Agreement bear annual interest rates at either (a) the adjusted SOFR Rate (as customarily defined) (the “Adjusted Term 
SOFR Rate”) plus 2.25% to 3.25% or (b) the sum of (i) the greatest of (A) the prime rate of Wells Fargo, (B) the federal funds 
rate plus ½ of 1.0%, and (C) the Adjusted Term SOFR Rate for an interest rate period of one month plus 1.0%, (ii) plus 1.25% 
to 2.25%, depending on the amount borrowed under the Credit Agreement. Principal amounts outstanding under the Credit 
Agreement are due and payable in full at maturity on June 2, 2027. All of the obligations under the Credit Agreement, and the 
guarantees of those obligations, are secured by substantially all of EEH’s assets. Additional payments due under the Credit 
Agreement include paying a commitment fee of 0.375% to 0.50% per year, depending on the amount borrowed under the Credit 
Agreement, to the Lenders in respect of the unutilized commitments thereunder. EEH is also required to pay customary letter of 
credit fees.
The 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, pay dividends and 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 Credit Agreement requires EEH to maintain the following financial covenants: a current ratio, (as such term is 
defined in the Credit Agreement) of not less than 1.0 to 1.0 and a consolidated leverage ratio of not greater than 3.5 to 1.0. 
Consolidated 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 to (ii) EBITDAX for the applicable period, which was calculated as EBITDAX for the four consecutive 
fiscal quarters ending on such date. The term “EBITDAX” means, for any period, the sum of consolidated net income (loss) for 
such period plus (a) the following expenses or charges to the extent deducted from consolidated net income (loss) in such 
period: (i) interest, (ii) taxes, (iii) depreciation, (iv) depletion, (v) amortization, (vi) certain distributions to employees related to 
the stock compensation, (vii) certain transaction related expenses, (viii) reimbursed indemnification expenses related to certain 
dispositions and investments, (ix) non-cash extraordinary, usual, or nonrecurring expenses or losses, (x) other non-cash charges 
and minus (b) to the extent included in consolidated net income (loss) in such period: (i) non-cash income, (ii) gains on asset 
dispositions, disposals and abandonments outside of the ordinary course of business and (iii) to the extent not otherwise 
deducted from consolidated net income (loss), the aggregate amount of any pass-through cash distributions received by 
Borrower during such period in an amount equal to the aggregate amount of pass-through cash distributions actually made by 
Borrower during such period.
The 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 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, 2022, EEH was in compliance with the covenants 
under the Credit Agreement.
As of December 31, 2022, $270.1 million and $250.0 million of borrowings were outstanding under the revolving tranche and 
the term loan tranche of the Credit Agreement, respectively, bearing annual interest of 7.238% and 7.670%, 
respectively, resulting in an additional $679.9 million of borrowing availability under the Credit Agreement. At December 31, 
2021, there were $320.0 million of borrowings outstanding under the Credit Agreement.
For the year ended December 31, 2022, the Company had borrowings of $3.1 billion and $3.1 billion in repayments of 
borrowings.
For the year ended December 31, 2022, interest on the revolving tranche of the Credit Agreement averaged 4.74% per annum, 
which excluded commitment fees of $1.7 million and amortization of deferred financing costs of $3.2 million. For the year 
EARTHSTONE ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
F-32

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.
During the year ended December 31, 2022, the Company capitalized $6.5 million and $5.8 million of costs associated with the 
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 year ended December 31, 2021. No costs associated with the Credit Agreement 
were capitalized during the 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.
8.000% Senior Notes
On April 12, 2022, EEH issued $550.0 million aggregate principal amount of unsecured 8.000% senior notes due 2027 (the 
“Notes”) for net proceeds of approximately $537.2 million (after deducting underwriting discounts and commissions) (the 
“Notes Offering”) which was used primarily to fund the Bighorn Acquisition and the remainder for general corporate purposes.
On April 12, 2022, in connection with the completion of the Notes Offering, EEH entered into an indenture, dated as of April 
12, 2022 (the “Indenture”), among EEH, the guarantors party thereto and U.S. Bank Trust Company, National Association, as 
trustee.
The Notes will mature on April 15, 2027 with interest accruing at a rate of 8.000% per annum payable semi-annually in cash in 
arrears on April 15 and October 15 of each year, which commenced on October 15, 2022. Before April 15, 2024, EEH may 
redeem some or all of the Notes at a redemption price equal to 100% of the aggregate principal amount of the Notes redeemed 
plus the “applicable premium” as of and accrued and unpaid interest, if any. EEH may redeem, at its option, all or part of the 
Notes at any time on or after April 15, 2024, at the applicable redemption price plus accrued and unpaid interest to, but not 
including, the date of redemption. Further, before April 15, 2024, EEH may on one or more occasions redeem up to 35% of the 
aggregate principal amount of the Notes in an amount not exceeding the net proceeds from one or more private or public equity 
offerings at a redemption price of 108.000% of the principal amount of the Notes, plus accrued and unpaid interest to the date 
of redemption, if at least 65% of the aggregate principal amount of the Notes remains outstanding immediately after such 
redemption and the redemption occurs within 180 days of the closing date of each such equity offering. Upon a Change of 
Control (as defined in the Indenture) EEH must offer to repurchase the Notes on terms and conditions set forth in detail in the 
Indenture.
The Notes are guaranteed on a senior unsecured basis by the Company and its subsidiaries (the “Guarantors”) and may be 
guaranteed by certain of EEH’s future restricted subsidiaries. The Notes are unsecured, rank equally in right of payment with all 
existing and future senior unsecured indebtedness of EEH and the Guarantors and rank senior in right of payment to any future 
subordinated indebtedness of EEH and the Guarantors. The Notes will rank effectively junior to all secured indebtedness of 
EEH and the Guarantors, including indebtedness under the Credit Agreement, to the extent of the value of the assets securing 
such indebtedness. The Notes will rank structurally junior in right of payment to all indebtedness and other liabilities, including 
trade payables, of any future subsidiary of EEH that are not guarantors.
The Indenture restricts EEH’s ability and the ability of its Restricted Subsidiaries (as defined in the Indenture), including the 
Guarantors, to: (i) incur or guarantee additional indebtedness or issue certain types of preferred stock; (ii) pay dividends on 
capital stock or redeem, repurchase or retire its capital stock or subordinated indebtedness; (iii) transfer or sell assets; (iv) make 
investments; (v) create certain liens; (vi) enter into agreements that restrict dividends or other payments from its Restricted 
Subsidiaries to EEH; (vii) consolidate, merge or transfer all or substantially all of its assets; (viii) engage in transactions with 
affiliates; and (ix) create unrestricted subsidiaries. These covenants are subject to important exceptions and qualifications set 
forth in the Indenture. If the Notes achieve an Investment Grade Rating (as defined in the Indenture) or better from two of three 
of Moody’s Investors Service, Inc., S&P Global Ratings, or Fitch Ratings, Inc., many of these covenants will be suspended.
The Indenture contains customary events of default (each an “Event of Default”). If an Event of Default occurs and is 
continuing, the Trustee or the holders of not less than 25% in aggregate principal amount of the outstanding Notes may declare 
the unpaid principal of, premium, if any, and accrued but unpaid interest on, all the Notes then outstanding to be due and 
payable. Upon such a declaration, such principal, premium, if any, and interest will be due and payable immediately. If an 
Event of Default relating to certain events of bankruptcy or insolvency of EEH or any Significant Subsidiary (as defined in the 
Indenture) occurs, the principal of, premium, if any, and the interest on, all the Notes will become immediately due and payable 
without any declaration or other act on the part of the Trustee or any holders of the Notes. Under certain circumstances, the 
holders of a majority in principal amount of the outstanding Notes may rescind any such acceleration with respect to the Notes 
and its consequences.
EARTHSTONE ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
F-33

During the year ended December 31, 2022, the Company capitalized $12.7 million of costs associated with the Notes. No costs 
associated with the Notes were capitalized during the years ended December 31, 2021 and 2020. The Company’s policy is to 
capitalize the debt issuance costs associated with the Notes and amortize those costs on a straight-line basis over the term of the 
Notes.
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.
Note 13. Asset Retirement Obligations
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.
The following table summarizes the Company’s asset retirement obligation transactions recorded during the years ended 
December 31, 2022 and 2021 (in thousands):
 
2022
2021
Beginning asset retirement obligations
$ 
15,866 $ 
3,027 
Associated with acquisitions
 
20,078  
9,821 
Liabilities incurred
 
533  
163 
Property dispositions
 
(10,284)  
(41) 
Liabilities settled
 
(910)  
(185) 
Accretion expense
 
2,652  
1,065 
Revision of estimates
 
2,625  
2,016 
Ending asset retirement obligations
$ 
30,560 $ 
15,866 
Note 14. Related Party Transactions
FASB ASC Topic 850, Related Party Disclosures, requires that information about transactions with related parties that would 
make a difference in decision making shall be disclosed so that users of the financial statements can evaluate their significance. 
The Audit Committee of the Board independently reviews and approves all related party transactions.
Earthstone has three significant shareholders that consist of various investment funds managed by each of the three private 
equity firms who may manage other investments in entities with which the Company interacts in the normal course of business 
(the “Significant Shareholders” or separately, each a “Significant Shareholder”). 
On February 12, 2020, the Company sold certain of its interests in oil and natural gas leases and wells in a transaction to a 
portfolio company of a Significant Shareholder (not under common control) for cash consideration of approximately 
$0.4 million. 
As discussed in Note 4. Acquisitions and Divestitures, on March 31, 2021, the Company entered into the Tracker/Sequel 
Purchase Agreements. The Tracker/Sequel Acquisitions were consummated on July 20, 2021, whereby the Company acquired 
the Tracker Assets for a purchase price of $18.8 million in cash and 4.7 million shares of Class A Common Stock. A Significant 
Shareholder owned approximately 49% of Tracker as of the closing of the Tracker Acquisition. A majority of the stockholders 
of Earthstone not affiliated with the Significant Shareholder approved the issuance of 6.2 million shares of Class A Common 
Stock in connection with the closing of the Tracker/Sequel Purchase Agreements at Earthstone’s Annual Meeting of 
Stockholders held on July 20, 2021.
As discussed in Note 4. Acquisitions and Divestitures, during the second quarter of 2021, the Company completed the Eagle 
Ford Acquisitions for a purchase price of approximately $45.2 million in cash. A Significant Shareholder controlled one of the 
four sellers. After participating in a competitive sales process, the Company acquired the aforementioned assets for $8.2 million 
in cash from that related party entity.
As discussed in Note 4. Acquisitions and Divestitures, the Chisholm Acquisition was consummated on February 15, 2022, 
whereby the Company acquired the Chisholm Assets for a purchase price of $377.5 million in cash, net of customary purchase 
price adjustments, and approximately 19.4 million shares of Class A Common Stock. A Significant Shareholder was the 
majority owner of Chisholm as of the closing of the Chisholm Acquisition. The deferred payment of $70 million as of March 
31, 2022 was paid on April 15, 2022 and included in Deferred acquisition payment – Chisholm in the Condensed Consolidated 
Balance Sheet as of March 31, 2022. The issuance of approximately 19.4 million shares of Class A Common Stock in 
connection with the closing of the Chisholm Agreement was (1) approved by a majority of the voting power of all outstanding 
EARTHSTONE ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
F-34

disinterested shares of the Common Stock and (2) increased the Significant Stockholder's beneficial ownership of Class A 
Common Stock from approximately 25% to 36% as of February 15, 2022.
On January 30, 2022, Earthstone entered into the SPA with certain affiliates of EnCap and Post Oak (collectively, the 
“Investors”) to issue 220,000 shares and 60,000 shares, respectively, of the Series A Convertible Preferred Stock. On April 14, 
2022, the SPA was consummated resulting in the issuance of the total of 280,000 shares of the Series A Convertible Preferred 
Stock in exchange for cash proceeds of $279.3 million, net of offering costs.
On July 6, 2022, the Series A Convertible Preferred Stock automatically converted into 25,225,225 shares of Class A Common 
Stock.
The Company paid $0.5 million to one of its Significant Shareholders for reimbursement of certain costs associated with the 
Bighorn Acquisition and related SPA.
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 
“Repurchase”). Additionally, on October 11, 2022, affiliates of Warburg sold 3,750,000 shares of Class A Common Stock to an 
unrelated party for $14.58 per share (collectively with the Repurchase, the “Warburg Sales”). Immediately preceding the 
Warburg Sales, Warburg owned approximately 18.7% of the outstanding Class A Common Stock and 14.1% of the Class A 
Common Stock and Class B Common Stock combined. Immediately following the Warburg Sales and through December 31, 
2022, Warburg owned approximately 12.3% of the Class A Common Stock and 9.3% of the Class A Common Stock and Class 
B Common Stock combined.
Note 15. Commitments and Contingencies
Contractual Commitments
Future minimum contractual commitments as of December 31, 2022 under non-cancellable agreements having initial or 
remaining terms in excess of one year are as follows: 
 
2023
2024
2025
2026
2027
Thereafter
Office leases
 
1,138  
1,160  
868  
1,052  
961  
327 
Automobile leases
 
907  
724  
200  
—  
—  
— 
Total
$ 
2,045 $ 
1,884 $ 
1,068 $ 
1,052 $ 
961 $ 
327 
Additionally, the Company leases corporate office space in The Woodlands, Texas; Midland, Texas and San Angelo, Texas. 
Rent expense was approximately $0.9 million, $0.8 million and $0.8 million, for the years ended December 31, 2022, 2021 and 
2020, respectively. Minimum lease payments under the terms of non-cancellable operating leases as of December 31, 2022 are 
included in the table above.
Environmental
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.
Legal
George Assad, et. al. v. EnCap Investments L.P., et. al.: On September 12, 2022, a complaint (the “Complaint”) styled as a 
“derivative action” was filed in the Delaware Court of Chancery (the “Court”) by George Assad (the “plaintiff”) a purported 
holder of a small number of shares of Class A Common Stock against Earthstone, six of its 10 directors and EnCap, a principal 
stockholder. The Complaint alleges that a majority of Earthstone’s directors were conflicted and, along with EnCap, breached 
their fiduciary duties in approving the sale of shares of Series A Convertible Preferred Stock that is convertible into Class A 
F-35

Common Stock pursuant to the SPA. The plaintiff requested the Court to declare that the defendants breached their fiduciary 
duties, award of unspecified monetary damages, including interest and costs, and/ or rescind the stock purchase transaction. On 
October 14, 2022, the defendants filed a motion to dismiss the amended Complaint. Earthstone believes the Complaint is 
completely without merit and intends to contest vigorously the allegations made therein and to seek reimbursement for its costs 
and expenses in so doing. Earthstone carries insurance for the claims asserted against it and the officer and director defendants 
in the Complaint, and the carrier has accepted coverage subject to applicable self-retentions and limits of liability. The 
Company does not expect this case to have a material adverse effect on the results of operations, financial position or cash 
flows of the Company.
From time to time, the Company may be involved in other various legal proceedings and claims in the ordinary course of 
business.
Note 16. Income Taxes
The Company’s corporate structure requires the filing of two separate consolidated U.S. Federal income tax returns and one 
Canadian income tax return which include Lynden US, Earthstone, and Lynden Corp. As such, taxable income of Earthstone 
cannot be offset by tax attributes, including net operating losses, of Lynden US, nor can taxable income of Lynden US be offset 
by tax attributes of Earthstone. Earthstone and Lynden US record a tax provision, respectively, for their share of the book 
income or loss of EEH, net of the non-controlling interest. 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.
The following table shows the components of the Company’s income tax provision for the years ended December 31, 2022, 
2021 and 2020 (in thousands):
 
Years Ended December 31,
 
2022
2021
2020
Current:
 
 
Federal
$ 
— 
$ 
— $ 
— 
State
 
1,811 
 
625  
545 
Total current
 
1,811 
 
625  
545 
Deferred:
Federal
 
114,876 
 
901  
(147) 
State
 
7,729 
 
333  
(510) 
Total deferred
 
122,605 
 
1,234  
(657) 
Total income tax expense (benefit)
$ 
124,416 
$ 
1,859 $ 
(112) 
 
Effective Tax Rate
A reconciliation of the effective tax rate to the federal statutory rate for the years ended December 31, 2022, 2021 and 2020 is 
as follows (in thousands, except percentages):
 
Years Ended December 31,
 
2022
2021
2020
Net income (loss) before income taxes
$ 775,033 
$ 63,365 
$ (29,546) 
Statutory rate
 21 %
 21 %
 21 %
Tax expense (benefit) computed at statutory rate
 162,757 
 
13,307 
 
(6,204) 
Noncontrolling interest
 
(41,743) 
 
(5,613) 
 
3,349 
Non-deductible general and administrative expenses
 
1,360 
 
(455) 
 
1,943 
Return to accrual and other true-up
 
(73) 
 
— 
 
157 
State income taxes, net of Federal benefit
 
9,187 
 
958 
 
35 
Valuation allowance
 
(7,072) 
 
(6,338) 
 
608 
Total income tax expense (benefit)
$ 124,416 
$ 
1,859 
$ 
(112) 
Effective tax rate
 16.1 %
 2.9 %
 0.4 %
During the year ended December 31, 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) 
EARTHSTONE ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
F-36

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 $0.11 million which included (1) 
deferred income tax benefit for Lynden US of $0.15 million as a result of its share of the distributable income from EEH, (2) 
deferred income tax benefit for Earthstone of $0.61 million as a result of its share of the distributable income from EEH, which 
was used to reduce the valuation allowance recorded against its deferred tax asset cannot be assured and (3) current income tax 
expense of $0.55 million, offset by deferred income tax benefit of $0.51 million related to the Texas Margin Tax. Lynden Corp 
incurred no material income or loss, or related income tax expense or benefit, for the year ended December 31, 2020.
Deferred Tax Assets and Liabilities
The Company’s deferred tax position reflects the net tax effects of the temporary differences between the carrying amounts of 
assets and liabilities for financial reporting purposes and the amounts used for income tax reporting. Significant components of 
the deferred tax assets and liabilities at December 31, 2022 and 2021 are as follows (in thousands):
 
Years Ended December 31,
 
2022
2021
Deferred noncurrent income tax assets (liabilities):
 
 
Oil & gas properties
$ 
11,437 $ 
20,909 
Basis difference in subsidiary obligation
 
(2,364)  
(2,211) 
Investment in Partnerships
 
(186,925)  
(40,141) 
Federal net operating loss carryforward
 
40,695  
16,544 
Interest limitation
 
2,581  
— 
Net deferred noncurrent tax (liability) asset
 
(134,576)  
(4,899) 
Valuation allowance
 
(3,760)  
(10,832) 
Net deferred tax liability
$ 
(138,336) $ 
(15,731) 
As of December 31, 2022, the Company had a valuation allowance recorded against its deferred tax asset of $3.8 million which 
is in excess of its net deferred noncurrent tax liabilities of $134.6 million, as presented above. The Company’s corporate 
organizational structure requires the filing of two separate consolidated U.S. Federal corporate 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, 2022, the deferred tax assets and liabilities related to the two U.S. 
Federal corporate income tax returns, one Canadian income tax return and one related to the Texas Margin Tax are a $113.7 
million deferred tax liability, a $18.5 million deferred tax liability, a $3.8 million deferred tax asset and a $6.1 million deferred 
tax liability, respectively, before considering the valuation allowance of $3.8 million.
As of December 31, 2021, the Company had a valuation allowance recorded against its deferred tax assets of $10.8 million 
which is in excess of its Net deferred noncurrent tax assets of $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, 2021, the deferred tax assets and liabilities related to the two U.S. 
Federal income tax returns, one Canadian income tax and one related to the Texas Margin Tax were a $19.7 million deferred 
tax asset, a $10.4 million deferred tax liability, a $3.8 million deferred tax asset and a $5.3 million deferred tax liability, 
respectively, before considering the valuation allowance of $10.8 million.
As of December 31, 2022, (1) Earthstone had estimated U.S. net operating loss carryforwards of $29.1 million, expiring in 2036 
and 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 
EARTHSTONE ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
F-37

carryforward life, and, (3) Lynden Corp had Canadian net operating loss carryforwards of $10.0 million, the first expiring in 
2024 and the last in 2037. ICL loss deductions are limited to 80% of the excess of taxable income in the year utilized. 
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”). On February 15, 2022, the Company completed the Chisholm Acquisition which included the 
issuance of 19,417,476 shares of Class A Common Stock, which resulted in an ownership change within the meaning of Sec 
382. As a result of the ownership change, the Company’s annual usage of net operating 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 
which, $85.3 million relates to the time period post ownership change within the meaning of Section 382 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 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.
Uncertain Tax Positions
FASB ASC Topic 740, Income Taxes (“ASC 740”) prescribes a recognition threshold and a measurement attribute for the 
financial statement recognition and measurement of income tax positions taken or expected to be taken in an income tax return. 
For those benefits to be recognized, an income tax position must be more-likely-than-not to be sustained upon examination by 
taxing authorities. As of December 31, 2022, the Company had no material uncertain tax positions. The Company’s uncertain 
tax positions may change in the next twelve months; however, the Company does not expect any possible change to have a 
significant impact on its results of operations or financial position.
The Company files two 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, 2022, the Company did not have any accrued interest or penalties associated with any uncertain tax liabilities.
Note 17. Defined Contribution Plan
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 100% of employee contributions, not to exceed six percent of the employee’s annual eligible compensation. 
The Company’s matching contributions vest immediately. The Company’s contributions to the 401(k) Plan for the years ended 
December 31, 2022, 2021 and 2020 were $1.1 million, $0.5 million and $0.5 million, respectively.
Note 18. Leases
The Company’s operating lease activities consist of leases for office space. The Company’s finance lease activities consist of 
leases for vehicles. Leases with an initial term of 12 months or less are not recorded on the balance sheet. Most leases include 
one or more options to renew, with renewal terms generally ranging from one to three years. The exercise of lease renewal 
options is at the Company’s sole discretion. Certain leases also include options to purchase the leased property. The depreciable 
life of assets and leasehold improvements is limited by the expected lease term, unless there is a transfer of title or purchase 
option reasonably certain of exercise. None of the lease agreements include variable lease payments. The lease agreements do 
not contain any material residual value guarantees or material restrictive covenants. 
The following table shows the classification and location of the Company’s leases on the Consolidated Balance Sheets (in 
thousands):
EARTHSTONE ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
F-38

December 31,
Leases
Balance Sheet Location
2022
2021
Assets
Noncurrent:
Operating
Operating lease right-of-use assets
$ 
4,569 $ 
1,795 
Finance
Office and other equipment, net of accumulated depreciation and 
amortization
 
1,678  
— 
Total lease assets
$ 
6,247 $ 
1,795 
Liabilities
Current:
Operating
Operating lease liabilities
$ 
842 $ 
681 
Finance
Finance lease liabilities
 
802  
— 
Noncurrent:
Operating
Operating lease liabilities
 
3,889  
1,276 
Finance
Finance lease liabilities
 
876  
— 
Total lease liabilities
$ 
6,409 $ 
1,957 
The following table shows the classification and location of the Company’s lease costs on the Consolidated Statements of 
Operations (in thousands):
Years Ended December 31,
Statement of Operations Location
2022
2021
2020
Operating lease expense
General and administrative expense
$ 
884 $ 
803 $ 
786 
Finance lease expense:
Amortization of right-of-use assets
Depreciation, depletion and amortization
$ 
549 $ 
74 $ 
217 
Interest on lease liability
Interest expense, net
 
100  
2  
13 
Total lease expense
$ 
1,533 $ 
879 $ 
1,016 
Additionally, the Company capitalized as part of oil and gas properties $23.9 million, $6.4 million and $2.9 million of short-
term lease costs related to drilling rig contracts during the years ended December 31, 2022, 2021 and 2020. All of the 
Company’s drilling rig contracts have enforceable terms of less than one year.
Minimum contractual obligations for the Company’s leases (undiscounted) as of December 31, 2022 were as follows (in 
thousands):
Operating
Finance
2023
$ 
1,138 $ 
907 
2024
 
1,160  
724 
2025
 
868  
200 
2026
 
1,052  
— 
2027
 
961  
— 
Thereafter
 
327  
— 
Total lease payments
$ 
5,506 $ 
1,831 
Less imputed interest
 
(775)  
(153) 
Total lease liability
$ 
4,731 $ 
1,678 
F-39

The following table shows the weighted average remaining lease term and the weighted average discount rate for the 
Company’s leases as of the dates indicated:
December 31, 2022
December 31, 2021
Operating 
Leases
Finance 
Leases
Operating 
Leases
Finance 
Leases
Weighted-average remaining lease term (in years)
4.1
2.3
2.9
n/a
Weighted-average discount rate (1)
 6.67 %
 8.00 %
 4.35 %
n/a
(1)
The discount rate used for operating leases is based on the Company’s incremental borrowing rate at lease 
commencement and may be adjusted if modifications to lease terms or lease reassessments occur. The 
discount rate used for finance leases is based on the rates implicit in the leases.
The following table includes other quantitative information for the Company’s leases (in thousands):
Years Ended December 31,
2022
2021
Cash paid for amounts included in the measurement of lease liabilities:
Cash payments for operating leases
$ 
857 $ 
778 
Cash payments for finance leases
 
649  
70 
Right-of-use assets obtained in exchange for new operating lease liabilities
 
3,447  
— 
Right-of-use assets obtained in exchange for new finance lease liabilities
 
2,227  
— 
Note 19. Supplemental Disclosures
Accounts Payable
The following table summarizes the Company’s current accounts payable at December 31, 2022 and 2021 (in thousands):
 
December 31,
2022
2021
Accounts payable related to vendors
 
76,044  
22,877 
Accounts payable related to severance taxes
 
10,380  
2,603 
Other
 
5,391  
5,917 
Total accounts payable
$ 
91,815 $ 
31,397 
Revenue and Royalties Payable
The following table summarizes the Company’s current revenues and royalties payable at December 31, 2022 and 2021 (in 
thousands):
 
December 31,
2022
2021
Revenue held in suspense
$ 
101,838 $ 
14,777 
Revenue and royalties payable
 
61,530  
21,412 
Total revenue and royalties payable
$ 
163,368 $ 
36,189 
F-40

Accrued Expenses
The following table summarizes the Company’s current accrued expenses at December 31, 2022 and 2021 (in thousands):
 
December 31,
2022
2021
Accrued capital expenditures
$ 
38,482 $ 
10,563 
Accrued lease operating expenses
 
14,173  
2,858 
Accrued interest
 
10,995  
648 
Accrued general and administrative expense
 
7,351  
8,011 
Accrued ad valorem taxes
 
4,243  
544 
Other
 
5,698  
9,080 
Total accrued expenses
$ 
80,942 $ 
31,704 
Supplemental Cash Flow Information 
The following table provides supplemental disclosures of cash flow information for the years ended December 31, 2022, 2021 
and 2020 (in thousands):
 
Years Ended December 31,
2022
2021
2020
Cash paid for:
Interest
$ 
12,520 $ 
9,648 $ 
4,588 
Income taxes
$ 
625 $ 
325 
Non-cash investing and financing activities:
Class A Common Stock issued in Chisholm Acquisition
$ 
249,515 $ 
— $ 
— 
Class A Common Stock issued in Bighorn Acquisition
$ 
77,757 $ 
— $ 
— 
Class A Common Stock issued in Titus Acquisition
$ 
53,574 $ 
— $ 
— 
Class A Common Stock issued in IRM Acquisition
$ 
— $ 
76,572 $ 
— 
Class A Common Stock issued in Tracker/Sequel Acquisition
$ 
— $ 
61,814 $ 
— 
Class A Common Stock issued in Foreland Acquisition
$ 
— $ 
28,121 $ 
— 
Accrued capital expenditures
$ 
58,569 $ 
23,558 $ 
7,328 
Lease asset additions - ASC 842
$ 
5,674 $ 
— $ 
— 
Asset retirement obligations
$ 
3,158 $ 
2,178 $ 
762 
Note 20. Supplemental Information On Oil And Gas Exploration And Production Activities (Unaudited)
Costs Incurred Related to Oil and Gas Activities
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.
F-41

The Company’s oil and natural gas activities for 2022, 2021 and 2020 were entirely within the United States of America. Costs 
incurred in oil and natural gas producing activities were as follows (in thousands):
 
Years Ended December 31,
 
2022
2021
2020
Acquisition cost:
 
 
Proved
$ 
1,934,602 $ 
465,144 $ 
— 
Unproved
 
77,378  
43  
— 
Exploration costs:
Geological and geophysical
 
2,492  
341  
298 
Development costs
 
538,114  
134,035  
67,550 
Total additions
$ 
2,552,586 $ 
599,563 $ 
67,848 
During the years ended December 31, 2022, 2021 and 2020, additions to oil and natural gas properties of $3.2 million, $2.2 
million and $0.8 million, respectively, were recorded for estimated costs of future abandonment related to new wells drilled or 
acquired.
During the years ended December 31, 2022, 2021 and 2020, the Company had no capitalized exploratory well costs, nor 
capitalized costs related to share-based compensation, general corporate overhead or similar activities.
Capitalized Costs
Capitalized costs, impairment, and depreciation, depletion and amortization relating to the Company’s oil and natural gas 
properties producing activities, all of which are conducted within the continental United States as of December 31, 2022 and 
2021, are summarized below (in thousands):
 
December 31,
 
2022
2021
Oil and gas properties, successful efforts method:
 
 
Proved properties
$ 
4,088,553 $ 
1,726,019 
Accumulated impairment to proved properties
 
(100,652)  
(100,652) 
Proved properties, net of accumulated impairments
 
3,987,901  
1,625,367 
Unproved properties
 
349,905  
289,341 
Accumulated impairment to Unproved properties
 
(67,316)  
(67,316) 
Unproved properties, net of accumulated impairments
 
282,589  
222,025 
Land
 
5,482  
5,382 
Total oil and gas properties, net of accumulated impairments
 
4,275,972  
1,852,774 
Accumulated depreciation, depletion and amortization
 
(619,196)  
(395,625) 
Net oil and gas properties
$ 
3,656,776 $ 
1,457,149 
Oil and Natural Gas Reserves
Users of this information should be aware that the process of estimating quantities of “proved” and “proved developed” oil and 
natural gas reserves is very complex, requiring significant subjective decisions in the evaluation of all available geological, 
engineering and economic data for each reservoir. The data for a given reservoir may also change substantially over time as a 
result of numerous factors including, but not limited to, additional development activity, evolving production history and 
continual reassessment of the viability of production under varying economic conditions. As a result, revisions to existing 
reserve estimates may occur from time to time. Although every reasonable effort is made to ensure reserve estimates reported 
represent the most accurate assessments possible, the subjective decisions and variances in available data for various reservoirs 
make these estimates generally less precise than other estimates included in the financial statement disclosures.
Proved reserves represent estimated quantities of oil, natural gas and natural gas liquids that geological and engineering data 
demonstrate, with reasonable certainty, to be recoverable in future years from known reservoirs under economic and operating 
conditions in effect when the estimates were made. Proved developed reserves represent estimated quantities expected to be 
recovered through wells and equipment in place and under operating methods used when the estimates were made.
F-42

The proved reserves estimates shown herein for the years ended December 31, 2022, 2021 and 2020 have been prepared by 
Cawley, Gillespie & Associates, Inc., independent petroleum engineers. Proved reserves were estimated in accordance with 
guidelines established by the SEC, which require that reserve estimates be prepared under existing economic and operating 
conditions based upon the 12-month unweighted average of the first-day-of-the-month prices.
The reserve information in these Consolidated Financial Statements represents only estimates. There are a number of 
uncertainties inherent in estimating quantities of proved reserves, including many factors beyond the Company’s control, such 
as commodity pricing. Reserve engineering is a subjective process of estimating underground accumulations of oil and natural 
gas that cannot be measured in an exact manner. The accuracy of any reserve estimate is a function of the quality of available 
data and engineering and geological interpretation and judgment. As a result, estimates by different engineers may vary. In 
addition, results of drilling, testing and production subsequent to the date of an estimate may lead to revising the original 
estimate. Accordingly, initial reserve estimates are often different from the quantities of oil and natural gas that are ultimately 
recovered. The meaningfulness of such estimates depends primarily on the accuracy of the assumptions upon which they were 
based. Except to the extent the Company acquires additional properties containing proved reserves or conducts successful 
exploration and development activities or both, the Company’s proved reserves will decline as reserves are produced.
The following table illustrates the Company’s estimated net proved reserves, including changes, and proved developed and 
proved undeveloped reserves for the periods indicated. The oil prices as of December 31, 2022, 2021 and 2020 are 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 $93.67 per barrel, $66.56 per barrel and $39.57 per barrel, respectively. The natural gas prices as of December 
31, 2022, 2021 and 2020 are based on the respective 12-month unweighted average of the first of month prices of the Henry 
Hub spot price which equates to $6.36 per MMBtu, $3.60 per MMBtu and $1.99 per MMBtu, respectively. Natural gas liquids 
are made up of ethane, propane, isobutane, normal butane and natural gasoline, each of which have different uses and different 
pricing characteristics. The natural gas liquids prices used to value reserves as of December 31, 2022, 2021 and 2020 averaged 
$39.24 per barrel, $30.16 per barrel and $11.61 per barrel, respectively. All prices are adjusted by lease or field for energy 
content, transportation fees, and market differentials, resulting in the aforementioned oil, natural gas and natural gas liquids 
reserves as of December 31, 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.
F-43

A summary of the Company’s changes in quantities of proved oil, natural gas and natural gas liquid reserves for the years ended 
December 31, 2022, 2021 and 2020 are as follows:
Oil
(MBbl)
Natural Gas
(MMcf)
Natural Gas 
Liquids
(MBbl)
Total
(MBoe)
Balance - December 31, 2019
 
52,650  
107,990  
23,688  
94,336 
Extensions
 
420  
1,258  
230  
860 
Production
 
(3,180)  
(7,282)  
(1,237)  
(5,630) 
Revision to previous estimates
 
(9,800)  
9,249  
(2,432)  
(10,691) 
Balance - December 31, 2020
 
40,090  
111,215  
20,249  
78,875 
Extensions
 
7,016  
49,846  
6,532  
21,856 
Sales of minerals in place
 
(8)  
(1)  
—  
(8) 
Purchases of minerals in place
 
25,114  
106,539  
17,103  
59,973 
Production
 
(4,381)  
(14,505)  
(2,257)  
(9,055) 
Revision to previous estimates
 
(6,756)  
31,787  
(2,596)  
(4,054) 
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:
December 31, 2019
 
18,220  
35,120  
7,447  
31,521 
December 31, 2020
 
18,878  
55,764  
10,125  
38,298 
December 31, 2021
 
35,824  
190,999  
25,917  
93,575 
December 31, 2022
 
88,759  
574,762  
80,168  
264,721 
Proved undeveloped reserves:
December 31, 2019
 
34,430  
72,870  
16,241  
62,815 
December 31, 2020
 
21,212  
55,450  
10,123  
40,577 
December 31, 2021
 
25,251  
93,882  
13,114  
54,012 
December 31, 2022
 
49,641  
167,404  
25,673  
103,215 
F-44

The table below presents the quantities of proved oil, natural gas and natural gas liquids reserves attributable to noncontrolling 
interests as of December 31, 2022 and 2021 and 2020:
As of December 31, 2022
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 
As of December 31, 2021
Oil
(MBbl)
Natural Gas
(MMcf)
Natural Gas 
Liquids
(MBbl)
Total
(MBoe)
Proved developed
 
14,011  
74,702  
10,137  
36,598 
Proved undeveloped
 
9,876  
36,719  
5,129  
21,125 
Total proved
 
23,887  
111,421  
15,266  
57,723 
As of December 31, 2020
Oil
(MBbl)
Natural Gas
(MMcf)
Natural Gas 
Liquids
(MBbl)
Total
(MBoe)
Proved developed
 
10,113  
29,873  
5,424  
20,516 
Proved undeveloped
 
11,363  
29,704  
5,423  
21,737 
Total proved
 
21,476  
59,577  
10,847  
42,253 
Notable changes in proved reserves for the year ended December 31, 2022 included the following:
•
Extensions. In 2022, extensions of 29.9 MMBoe were primarily the result of successful drilling results in the 
Midland Basin.
•
Purchases of minerals in place. In 2022, the Company completed multiple acquisitions that resulted in 213.1 
MMBoe in additional reserves, as disclosed in Note 4. Acquisitions and Divestitures.
•
Revision to previous estimates. In 2022, the upward revisions of prior reserves of 10.5 MMBoe consisted of 
6.5 MMBoe related to changes in price and 4.0 MMBoe related to changes in performance and other 
economic factors.
Notable changes in proved reserves for the year ended December 31, 2021 included the following:
•
Extensions. In 2021, total extensions of 21.9 MMBoe were primarily the result of successful drilling results in 
the Midland Basin.
•
Purchases of mineral in place. In 2021, the Company completed multiple acquisitions that resulted in 60.0 
MMBoe in additional reserves, as disclosed above in Note 4. Acquisitions and Divestitures.
•
Revision to previous estimates. In 2021, the downward revisions of prior reserves of 4.1 MMBoe consisted of 
changes in anticipated well densities and changes in performance and other economic factors totaling 9.2 
MMBoe and 5.5 MMBoe, respectively, offset by a positive revision of 10.6 MMBoe related to changes in 
prices.
Notable changes in proved reserves for the year ended December 31, 2020 included the following:
•
Extensions. In 2020, total extensions of 860.0 MBoe were primarily the result of successful drilling results in 
the Midland Basin.
•
Revision to previous estimates. In 2020, the downward revisions of prior reserves of 10.7 MMBoe were 
composed of negative revisions due to the reclassification of 11.9 MMBoe of reserves from proved 
undeveloped to non-proved due to the SEC's five-year development rule and negative revisions of 2.7 
MMBoe due to changes in price offset by revisions of 3.9 MMBoe related to changes in performance and 
other economic factors.
For wells classified as proved developed producing where sufficient production history existed, reserves were based on 
individual well performance evaluation and production decline curve extrapolation techniques. For undeveloped locations and 
wells that lack sufficient production history, reserves were based on analogy to producing wells within the same area exhibiting 
similar geologic and reservoir characteristics. Well spacing was determined from drainage patterns derived from a combination 
F-45

of performance-based recoveries and analogous producing wells for each area or field. PUD locations were limited to areas of 
uniformly high-quality reservoir properties, between existing commercial producers where the reservoir can, with reasonable 
certainty, be judged to be continuous with existing producers and contain economically producible oil and natural gas on the 
basis of available geoscience and engineering data.
Changes in PUD reserves for the years ended December 31, 2022, 2021 and 2020 were as follows (in MBoe): 
Proved undeveloped reserves at December 31, 2019 (1)
 
62,815 
Conversions to developed
 
(8,200) 
Extensions
 
— 
Revision to previous estimates
 
(14,038) 
Proved undeveloped reserves at December 31, 2020 (2)
 
40,577 
Conversions to developed
 
(8,274) 
Extensions
 
20,521 
Purchases of minerals in place
 
11,577 
Revision to previous estimates
 
(10,389) 
Proved undeveloped reserves at December 31, 2021 (3)
 
54,012 
Conversions to developed
 
(22,637) 
Extensions
 
16,499 
Purchases of minerals in place
 
57,432 
Revision to previous estimates
 
(2,091) 
Proved undeveloped reserves at December 31, 2022 (4)
 
103,215 
(1)
Includes 34,243 MBoe attributable to noncontrolling interests.
(2)
Includes 21,737 MBoe attributable to noncontrolling interests.
(3)
Includes 21,125 MBoe attributable to noncontrolling interests.
(4)
Includes 25,293 MBoe attributable to noncontrolling interests.
2022 Changes in Proved Undeveloped Reserves
Conversions to developed. In the Company's year-end 2021 plan to develop its PUDs within five years, it was estimated that 
$190.2 million of capital would be expended in 2022 for the conversion of 45 gross / 31.8 net PUDs to add 24.5 MMBoe. In 
2022, the Company spent $191.2 million to convert 42 gross / 26.6 net PUDs adding 22.6 MMBoe to developed.
Extensions. In 2022, extensions of 16.5 MMBoe were primarily the result of successful drilling results in the Delaware Basin 
and the Midland Basin.
Purchases of minerals in place. In 2022, the Company completed multiple acquisitions that resulted in 57.4 MMBoe of 
additional reserves, as disclosed in Note 4. Acquisitions and Divestitures.
Revision to previous estimates. Downward revisions of prior reserves of 2.1 MMBoe consisted of 2.4 MMBoe related to 
changes in performance and other economic factors, offset by a positive revision of 0.3 MMBoe related to changes in prices.
2021 Changes in Proved Undeveloped Reserves
Conversions to developed. In the Company's year-end 2020 plan to develop its PUDs within five years, it was estimated that 
$41.1 million of capital would be expended in 2021 for the conversion of 13 gross / 10.5 net PUDs to add 6.7 MMBoe. In 2021, 
due to improved commodity prices, the Company spent $55.1 million to convert 16 gross / 13.1 net PUDs adding 8.3 MMBoe 
to developed.
Revision to previous estimates. Downward revisions of prior reserves of 10.4 MMBoe consisted of changes in anticipated well 
densities and changes in performance and other economic factors of 9.2 MMBoe and 2.9 MMBoe, respectively, offset by a 
positive revision of 1.7 MMBoe related to changes in prices.
2020 Changes in Proved Undeveloped Reserves
Conversions to developed. In the Company's year-end 2019 plan to develop its PUDs within five years, the Company estimated 
that $111.1 million of capital would be expended in 2020 for the conversion of 28 gross / 17.6 net PUDs to add 11.3 MMBoe. 
F-46

In 2020, due to unforeseeable conditions previously described, the Company spent $67.8 million to convert 18 gross / 10.3 net 
PUDs adding 8.2 MMBoe to developed.
Revision to previous estimates. The Company maintains a five-year development plan, reviewed annually to ensure capital is 
allocated to the wells that have the highest risk-adjusted rates of return within the Company's inventory of undrilled well 
locations. In response to lower commodity prices, the Company reduced the pace of activity in its five-year development plan. 
This resulted in the reclassification of 11.9 MMBoe of reserves from proved undeveloped to non-proved during the year ended 
December 31, 2020 due to the five-year development rule. Based on the Company's then-current acreage position, strip prices, 
anticipated well economics, and its development plans at the time these reserves were classified as proved, the Company's 
management believes the previous classification of these locations as proved undeveloped was appropriate. The remaining 
revisions of 2.1 MMBoe were primarily due to reduced commodity prices.
Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Natural Gas Reserves
The following Standardized Measure of Discounted Future Net Cash Flows (Standardized Measure) has been developed 
utilizing FASB ASC Topic 932, Extractives Activities – Oil and Gas (“ASC 932”) procedures and based on oil and natural gas 
reserve and production volumes estimated by the Company’s third-party petroleum engineering firm. It can be used for some 
comparisons, but should not be the only method used to evaluate the Company or its performance. Further, the information in 
the following table may not represent realistic assessments of future cash flows, nor should the Standardized Measure be 
viewed as representative of the current value of the Company.
The Company believes that the following factors should be taken into account when reviewing the following information:
•
Future costs and commodity prices will probably differ from those required to be used in these calculations;
•
Due to future market conditions and governmental regulations, actual rates of production in future years may 
vary significantly from the rate of production assumed in the calculations;
•
A 10% discount rate may not be reasonable as a measure of the relative risk inherent in realizing future net oil 
and natural gas revenues; and
•
Future net revenues may be subject to different rates of income taxation.
At December 31, 2022, 2021 and 2020, as specified by the SEC, the prices for oil and natural gas used in this calculation were 
the unweighted 12-month average of the first day of the month prices, except for volumes subject to fixed price contracts. 
Prices used to estimate reserves are included in Oil and Natural Gas Reserves above. Future production costs include per-well 
overhead expenses allowed under joint operating agreements, abandonment costs (net of salvage value), and a non-cancellable 
fixed cost agreement to reserve pipeline capacity of 10,000 MMBtu per day for gathering and processing. Estimates of future 
income taxes are computed using current statutory income tax rates including consideration for estimated future statutory 
depletion and tax credits. The resulting net cash flows are reduced to present value amounts by applying a 10% discount factor.
The Standardized Measure at December 31, 2022, 2021 and 2020 is as follows (in thousands):
 
December 31,
 
2022
2021
2020
Future cash inflows
$ 
21,506,026 $ 
6,042,508 $ 
1,902,073 
Future production costs
 
(6,362,901)  
(1,641,130)  
(633,248) 
Future development costs
 
(1,207,597)  
(470,008)  
(285,088) 
Future income tax expense
 
(1,910,370)  
(381,663)  
(35,557) 
Future net cash flows
 
12,025,158  
3,549,707  
948,180 
10% annual discount for estimated timing of cash flows
 
(5,300,657)  
(1,731,335)  
(487,327) 
Standardized measure of discounted future net cash flows (1)
$ 
6,724,501 $ 
1,818,372 $ 
460,853 
(1)
At December 31, 2022, 2021 and 2020, the portion of the standardized measure of discounted future net cash 
flows attributable to noncontrolling interests was $1.6 billion, $711.2 million and $246.9 million, 
respectively.
F-47

Changes in Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Natural Gas 
Reserves
The following is a summary of the changes in the Standardized Measure for the Company’s proved oil and natural gas reserves 
during each of the years in the three-year period ended December 31, 2022 (in thousands):
 
December 31,
 
2022
2021
2020
Beginning of year
$ 
1,818,372 $ 
460,853 $ 
789,577 
Sales of oil and gas produced, net of production costs
 
(1,341,586)  
(343,914)  
(105,555) 
Sales of minerals in place
 
(76,570)  
14  
14 
Net changes in prices and production costs
 
3,838,439  
1,346,851  
(381,769) 
Extensions and improved recoveries
 
1,178,521  
216,583  
14,644 
Changes in income taxes, net
 
(866,805)  
(185,757)  
17,826 
Previously estimated development costs incurred during the period
 
246,705  
41,120  
66,788 
Net changes in future development costs
 
(295,553)  
(104,223)  
258,741 
Purchases of minerals in place
 
2,011,980  
465,187  
— 
Revisions of previous quantity estimates
 
3,283  
(151,748)  
(273,781) 
Accretion of discount
 
345,642  
76,121  
81,999 
Changes in timing of estimated cash flows and other
 
(137,927)  
(2,715)  
(7,631) 
End of year (1)
$ 
6,724,501 $ 
1,818,372 $ 
460,853 
(1)
At December 31, 2022, 2021 and 2020, the portion of the standardized measure of discounted future net cash 
flows attributable to noncontrolling interests was $1.6 billion, $711.2 million and $246.9 million, 
respectively.
F-48

CODE OF BUSINESS CONDUCT AND ETHICS
(updated January 31, 2023)
I. INTRODUCTION
Set forth herein is the Code of Business Conduct and Ethics (this “Code”) adopted by 
Earthstone Energy, Inc. (“Earthstone” or the “Company”). This Code provides 
Earthstone’s principles and standards of conduct to guide all directors, officers and 
employees of Earthstone in our goal to achieve the highest business and personal 
ethical standards as well as compliance with the laws, rules and regulations that apply 
to our business. All of our directors, officers and employees are required to conduct 
themselves accordingly in every aspect of our business and seek to avoid even the 
appearance of improper behavior.
This Code is designed to deter wrongdoing and to promote:
 Honest and ethical conduct, including the ethical handling of actual or apparent 
conflicts of interest between personal and professional relationships;
 Full, fair, accurate, timely, and understandable disclosure in reports and 
documents that the Company files with the Securities and Exchange Commission 
(the “SEC”) and in other public communications;
 Compliance with applicable governmental laws, rules and regulations;
 Prompt internal reporting of violations of this Code; and
 Accountability for adherence to this Code.
II. CONFLICTS OF INTEREST
A conflict of interest exists when an individual’s private interest interferes in any way, or 
even appears to interfere, with the interests of the Company as a whole. A conflict 
situation can arise when a director, officer or employee takes actions or has interests 
that may make it difficult to perform his or her Company work objectively and effectively. 
Conflicts of interest also arise when a director, officer or employee, or members of his or 
her family, receives improper personal benefits as a result of his or her position with 
Earthstone.
No director, officer or employee may seek or accept from the Company any credit, an 
extension of credit or the arrangement of an extension of credit in the form of a personal 
loan.
A conflict of interest may arise for a director, officer or employee of the Company in a 
situation where such director, officer or employee has an interest in, accepts 
employment with, becomes involved with, or otherwise works for, any customer, 
supplier, vendor, contractor or competitor of Earthstone (except for an investment in 
publicly traded securities where such individual does not have the ability to influence or 
direct policies or management of such customer, supplier, vendor, contractor or 
competitor), including serving as a director of any customer, supplier, vendor, contractor 
or competitor of Earthstone. In such instances, the director, officer or employee should 
report such situation, in advance, to the appropriate internal personnel for analysis.
Exhibit 14.1

Directors, officers and employees should avoid situations that could be construed as a 
conflict of interest. Such situations, whether actual conflicts or not, give rise to concerns 
on the part of shareholders, analysts, the general public and other officers, directors and 
employees.  
Any director, officer or employee who becomes aware of a conflict or a potential conflict 
should bring it to the attention of a supervisor, manager or other appropriate personnel 
or follow the procedures described in Section XII of this Code.
III. INSIDER TRADING
Directors, officers and employees of Earthstone who have access to confidential 
information are not permitted to use or share that information for stock trading purposes 
or for any other purpose except the conduct of our business. All non-public information 
about the Company should be considered confidential information. To use non-public 
information for personal financial benefit or to "tip" others who might make an 
investment decision on the basis of this information is not only unethical but also illegal. 
Earthstone maintains an Insider Trading Policy and all Earthstone directors, officers and 
employees are required to comply with such policy. 
IV. CORPORATE OPPORTUNITIES
Except as set forth below in this Section IV, without the written consent of the 
Earthstone Board of Directors, directors, officers and employees are prohibited from 
taking for themselves an opportunity that is (a) a potential transaction or matter that may 
be an investment or business opportunity or prospective economic or competitive 
advantage in which the Company could reasonably have an interest or expectancy or 
(b) discovered through the use of corporate property, information or position. No 
director, officer or employee may use corporate property, information, or position for 
personal gain or competing with the Company directly or indirectly. Directors, officers 
and employees owe a duty to advance the legitimate interests of the Company when 
the opportunity to do so arises.
The members of the Earthstone Board of Directors employed by EnCap Investments 
L.P., Warburg Pincus, LLC, and Post Oak Energy Capital, L.P. or their affiliates 
(together, the “Investor Parties”), their affiliates and respective agents, shareholders, 
members, partners, officers, directors and employees, including any director or officer of 
the Company who is also a shareholder, member, partner, officer, director, or employee 
of any member of the Investor Parties, have participated (directly or indirectly) in and 
may, and shall have no duty not to, continue to (x) participate (directly or indirectly) in 
venture capital and other direct investments in corporations, joint ventures, limited 
liability companies and other entities conducting business of any kind, nature or 
description (“Other Investments”) and (y) have interests in, participate with, aid and 
maintain seats on the boards of directors or similar governing bodies of Other 
Investments, in each case that may, are or will be competitive with the business of the 
Company and its subsidiaries or in the same or similar lines of business as the 
Company and its subsidiaries, or that could be suitable for the Company or its 
subsidiaries.
To the fullest extent permitted by applicable law, the Company, on behalf of itself and its 
subsidiaries, renounces any interest or expectancy of the Company and its subsidiaries 
Exhibit 14.1

in, or in being offered an opportunity to participate in, any such Other Investment or any 
business opportunities for such Other Investments that are from time to time presented 
to any Investor Party or are business opportunities in which an Investor Party 
participates or desires to participate, even if the Other Investment or business 
opportunity is one that the Company or its subsidiaries might reasonably be deemed to 
have pursued or had the ability or desire to pursue if granted the opportunity to do so, 
and each such Investor Party shall have no duty to communicate or offer any such 
Other Investment or business opportunity to the Company.    
V. COMPETITION AND FAIR DEALING
We seek to outperform our competition fairly and honestly. We seek competitive 
advantages through superior performance, never through unethical or illegal business 
practices. Stealing proprietary information, possessing trade secret information that was 
obtained without the owner's consent, or inducing such disclosures by past or present 
employees of other companies is prohibited. No director, officer or employee of 
Earthstone shall take unfair advantage of anyone through manipulation, concealment, 
abuse of privileged information, misrepresentation of material facts, or any other unfair-
dealing practice.
The purpose of business entertainment and gifts in a commercial setting is to create 
goodwill and sound working relationships, not to gain unfair advantage with customers. 
No gift or entertainment should ever be offered, given, provided or accepted by any 
Company director, officer, employee, family member of any of the foregoing or agent 
unless it:
• Is not a cash gift;
• Is consistent with customary business practices;
• Is not excessive in value;
• Cannot be construed as a bribe or payoff; and
• Does not violate any laws or regulations.
VI. DISCRIMINATION AND HARASSMENT
The Company is firmly committed to providing equal employment opportunity to 
qualified individuals regardless of race, color, religion, gender, age, national origin, 
citizenship status, sexual orientation, disability, military service or reserve or veteran 
status, marital status, or other protected status. Earthstone will not tolerate illegal 
discrimination or harassment of any kind. Examples of harassment include derogatory 
comments based on racial or ethnic characteristics and unwelcome conduct of a sexual 
nature. All of our employees deserve a work environment where they will be respected 
and the Company is committed to providing an environment that supports honesty, 
integrity, respect, trust and responsibility.
VII. RECORD-KEEPING
Earthstone requires honest and accurate recording and reporting of information in order 
to make responsible business decisions.
Exhibit 14.1

Reimbursable expenses incurred by directors, officers and employees must be 
documented and recorded accurately. No one should rationalize or even consider 
misrepresenting facts or falsifying records.
All of the Company’s books, records, accounts and financial statements must be 
maintained in reasonable detail, must appropriately reflect Earthstone’s transactions, 
and must conform both to applicable legal requirements and to the Company’s system 
of internal controls and generally accepted accounting principles.
Business records and communications often become public, and we should avoid 
exaggeration, derogatory remarks, guesswork, or inappropriate characterizations of 
people and companies that can be misunderstood. This applies equally to e-mail, text 
messages, internal memos, and formal reports. Records should always be retained or 
destroyed according to Earthstone’s record retention policies.
VIII. FINANCIAL REPORTING AND DISCLOSURE
All transactions involving Earthstone and its subsidiaries must be documented, in 
reasonable detail, and accounted for on the books and records of the Company in 
accordance with generally accepted accounting principles and applicable laws and 
regulations. Earthstone’s Principal Accounting Officer is responsible for establishing and 
maintaining accounting policies and procedures, disclosure controls and internal control 
standards, and the requirements for financial reporting to the Company's Management 
and others.
IX. CONFIDENTIALITY
Directors, officers and employees must (i) safeguard the confidentiality of confidential 
information entrusted to them by the Company or its customers, except when disclosure 
is required by laws or regulations, and (ii) not use confidential information of the 
Company for any purpose other than in the performance of their duties for the 
Company. Confidential information includes all non-public information that might be of 
use to competitors, or harmful to Earthstone or its customers, if disclosed or used for an 
improper purpose. The obligation to preserve confidential information continues even 
after employment ends.
X. PROTECTION AND PROPER USE OF THE COMPANY ASSETS
All directors, officers and employees should endeavor to protect the Company's assets, 
including funds, property, electronic communications systems, information resources, 
data, facilities, equipment and supplies, and ensure their efficient use. Theft, 
carelessness and waste have a direct impact on Earthstone’s profitability. Any 
suspected incident of fraud or theft (including any cyber theft or cybersecurity incident) 
should be immediately reported for investigation pursuant to Section XII of this Code. 
Company assets and information should be used for legitimate Company purposes.
The obligation of directors, officers and employees to protect Earthstone’s assets 
includes its proprietary information. Proprietary information includes intellectual property 
such as trade secrets, software programs, as well as business, marketing and service 
plans, designs, databases, records, salary information and any unpublished financial 
Exhibit 14.1

data and reports. Unauthorized use or distribution of this information is a violation of 
Company policy and this Code. It could also be illegal and result in civil or criminal 
penalties.
XI. IMPROPER INFLUENCE ON CONDUCT OF AUDITS
No director, officer or employee of the Company shall take any action (e.g., offering or 
paying bribes or other financial incentives, providing inaccurate or misleading legal 
analysis, blackmailing, and making physical threats) or make any false, misleading or 
inaccurate oral or written statement to fraudulently influence, coerce, manipulate or 
mislead an independent auditor engaged in the performance of an audit of the 
Company’s financial statements for the purpose of rendering the financial statements 
materially misleading. This standard shall also include improper influence with respect 
to preparation of Earthstone’s oil and gas reserves by an independent petroleum 
engineering firm.
XII. REPORTING ANY ILLEGAL OR UNETHICAL BEHAVIOR
Earthstone encourages and promotes ethical behavior. Directors, officers and 
employees are encouraged to promptly discuss with, or otherwise disclose to, their 
supervisors, managers, the Company’s General Counsel or other appropriate personnel 
any observed or suspected violations of laws, rules, regulations or this Code.
Reporting of violations will remain confidential to the degree possible. The Company 
does not permit retaliation of any kind against employees for good faith reports of 
ethical violations or misconduct. No employee of the Company may be discharged, 
demoted, suspended, threatened, harassed or in any other manner be discriminated 
against in the terms and conditions of their employment because of reporting or aiding 
in the investigation of violations of laws, rules, regulations or this Code. Directors, 
officers and employees are expected to cooperate in internal investigations of 
misconduct.
For the avoidance of doubt, nothing in this Code is to be interpreted or applied in any 
way that prohibits, restricts or interferes with an employee’s (a) exercise of rights 
provided under, or participation in, “whistleblower” programs of the SEC or any other 
applicable regulatory agency or governmental entity (each, a “Government Body”), or 
(b) good faith reporting of possible violations of applicable law to any Government Body, 
including cooperating with a Government Body in any governmental investigation 
regarding possible violations of applicable law.
XIII. VIOLATIONS OF THE CODE AND DISCIPLINARY ACTION
Every director, officer and employee of the Company has a duty to adhere to this Code. 
If a law conflicts with a policy in this Code, you must comply with the law. Any individual 
who violates the standards in this Code is subject to disciplinary action, up to and 
including termination, or in the case of a director a request for resignation, and civil and 
criminal prosecution, if appropriate. Earthstone will promptly and properly document all 
reasons for disciplinary actions taken against its directors, officers and employees for 
violations of this Code.
XIV. WAIVERS OF THE CODE
Exhibit 14.1

Any waiver of this Code for directors or executive officers of Earthstone may be made 
only by the Company's Board of Directors and will be promptly disclosed if and as 
required by law, including the rules and regulations of the SEC, and the listing 
requirements of any applicable stock exchange. 
Exhibit 14.1

Exhibit 21.1
SUBSIDIARIES OF THE COMPANY
Jurisdiction of Organization
Earthstone Operating, LLC
Texas
Earthstone Energy Holdings, LLC
Delaware
Lynden Energy Corp.
British Columbia, Canada
Lynden USA Inc.
Utah
Earthstone Permian LLC
Texas
Sabine River Energy, LLC
Texas
Independence Resources Technologies, LLC
Delaware

Exhibit 23.1
CONSENT OF INDEPENDENT PETROLEUM ENGINEERS
The undersigned hereby consents to the references to our firm in the form and context in which they appear in the Annual 
Report on Form 10-K of Earthstone Energy, Inc. for the year ended December 31, 2022, as well as in the notes to the financial 
statements included therein. We also hereby consent to the incorporation by reference of the references to our firm, in the 
context in which they appear, and to our reserves report dated January 23, 2023 into the Registration Statements on Form S-3 
(File Nos. 333-205466, 333-213543, 333-218277, 333-224334, 333-254099, 333-254106, 333-258455, 333-260824, 
333-265982, 333-266020, 333-266164,  333-266165 and 333-267256) and Form S-8 (File Nos. 333-210734, 333-221248, 
333-227720, 333-240998 and 333-258456) filed with the U.S. Securities and Exchange Commission. 
Sincerely,
/s/ W. Todd Brooker
W. Todd Brooker, P.E.
President
Cawley, Gillespie & Associates, Inc.
Texas Registered Engineering Firm F-693
March 8, 2023
 

Exhibit 23.2
Consent of Independent Registered Public Accounting Firm
 
We consent to the incorporation by reference in the Registration Statements on Form S-3 (No. 333-205466, 
No. 333-213543, No. 333-218277, No. 333-224334, No. 333-254099, No. 333-254106, No. 333-258455, 
No. 333-260824, No. 333-265982, No. 333-266020, No. 333-266164, No. 333-266165, and No. 
333-267256) and Form S-8 (No. 333-210734, No. 333-221248 , No. 333-227720, No. 333-240998, and No. 
333-258456) of Earthstone Energy, Inc. (the “Company”), of our reports dated March 8, 2023, relating to 
the consolidated financial statements of the Company and the effectiveness of internal control over 
financial reporting of the Company, appearing in this Annual Report on Form 10-K of the Company for the 
year ended December 31, 2022.
/s/ Moss Adams LLP
Houston, Texas
March 8, 2023

Exhibit 31.1
CERTIFICATION PURSUANT TO
SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002
I, Robert J. Anderson, certify that:
1.
I have reviewed this annual report on Form 10-K of Earthstone Energy, Inc.;
2.
Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material 
fact necessary to make the statements made, in light of the circumstances under which such statements were made, not 
misleading with respect to the period covered by this report;
3.
Based on my knowledge, the financial statements, and other financial information included in this report, fairly present 
in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the 
periods presented in this report;
4.
The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and 
procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting 
(as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
a.
Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be 
designed under our supervision, to ensure that material information relating to the registrant, including its 
consolidated subsidiaries, is made known to us by others within those entities, particularly during the period 
in which this report is being prepared;
b.
Designed such internal control over financial reporting, or caused such internal control over financial 
reporting to be designed under our supervision, 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;
c.
Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report 
our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period 
covered by this report based on such evaluation; and
d.
Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred 
during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual 
report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control 
over financial reporting; and
5.
The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control 
over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or 
persons performing the equivalent functions):
a.
All significant deficiencies and material weaknesses in the design or operation of internal control over 
financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, 
summarize and report financial information; and
b.
Any fraud, whether or not material, that involves management or other employees who have a significant role 
in the registrant’s internal control over financial reporting.
Date: March 8, 2023
/s/ Robert J. Anderson
 
Robert J. Anderson
 
President, Chief Executive Officer and Director
 

Exhibit 31.2
CERTIFICATION PURSUANT TO
SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002
I, Tony Oviedo, certify that:
1.
I have reviewed this annual report on Form 10-K of Earthstone Energy, Inc.;
2.
Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material 
fact necessary to make the statements made, in light of the circumstances under which such statements were made, not 
misleading with respect to the period covered by this report;
3.
Based on my knowledge, the financial statements, and other financial information included in this report, fairly present 
in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the 
periods presented in this report;
4.
The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and 
procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting 
(as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
a.
Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be 
designed under our supervision, to ensure that material information relating to the registrant, including its 
consolidated subsidiaries, is made known to us by others within those entities, particularly during the period 
in which this report is being prepared;
b.
Designed such internal control over financial reporting, or caused such internal control over financial 
reporting to be designed under our supervision, 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;
c.
Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report 
our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period 
covered by this report based on such evaluation; and
d.
Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred 
during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual 
report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control 
over financial reporting; and
5.
The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control 
over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or 
persons performing the equivalent functions):
a.
All significant deficiencies and material weaknesses in the design or operation of internal control over 
financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, 
summarize and report financial information; and
b.
Any fraud, whether or not material, that involves management or other employees who have a significant role 
in the registrant’s internal control over financial reporting.
Date: March 8, 2023
/s/ Tony Oviedo
 
Tony Oviedo
 
Executive Vice President - Accounting and Administration

Exhibit 32.1
CERTIFICATION PURSUANT TO
18 U.S.C. SECTION 1350,
AS ADOPTED PURSUANT TO
SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002
In connection with the annual report on Form 10-K of Earthstone Energy, Inc. (the “Company”) for the period ended December 
31, 2022, as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Robert J. Anderson, 
President and Chief Executive Officer of the Company, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to 
Section 906 of the Sarbanes-Oxley Act of 2002, that:
1.
The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 
1934, as amended; and
2.
The information contained in the Report fairly presents, in all material respects, the financial condition and 
results of operations of the Company.
Date: March 8, 2023
/s/ Robert J. Anderson
 
Robert J. Anderson
 
President, Chief Executive Officer and Director
The foregoing certification is being furnished solely pursuant to 18 U.S.C. Section 1350 and is not being filed as part of the 
Report or as a separate disclosure document.
A signed original of this written statement required by Section 906 has been provided to, and will be retained by, the Company 
and furnished to the Securities and Exchange Commission or its staff upon request.

Exhibit 32.2
CERTIFICATION PURSUANT TO
18 U.S.C. SECTION 1350,
AS ADOPTED PURSUANT TO
SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002
In connection with the annual report on Form 10-K of Earthstone Energy, Inc. (the “Company”) for the period ended December 
31, 2022, as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Tony Oviedo, Executive 
Vice President – Accounting and Administration of the Company, certify, pursuant to 18 U.S.C. Section 1350, as adopted 
pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that:
1.
The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 
1934, as amended; and
2.
The information contained in the Report fairly presents, in all material respects, the financial condition and 
results of operations of the Company.
 
Date: March 8, 2023
/s/ Tony Oviedo
 
Tony Oviedo
 
Executive Vice President - Accounting and Administration
The foregoing certification is being furnished solely pursuant to 18 U.S.C. Section 1350 and is not being filed as part of the 
Report or as a separate disclosure document.
A signed original of this written statement required by Section 906 has been provided to, and will be retained by, the Company 
and furnished to the Securities and Exchange Commission or its staff upon request.
 

January 23, 2023
Geoff Vernon
Vice President of Reservoir Engineering and A&D
Earthstone Energy, Inc.
1400 Woodloch Forest Dr., Suite 300
The Woodlands, Texas 77380
 
Re: 
Evaluation Summary - SEC Price Case
 
 
 
Earthstone Energy, Inc. Interests
 
 
 
Total Proved Reserves
 
 
 
Certain Properties in New Mexico and Texas
 
 
As of December 31, 2022
 
 
        
 
 
 
 Pursuant to the Guidelines of the Securities and
 
 
 Exchange Commission for Reporting Corporate
 
 
 Reserves and Future Net Revenue
Dear Mr. Vernon:
As you have requested, this report was completed on January 23, 2023 for the purpose of submitting 
our estimates of proved reserves and forecasts of economics attributable to the Earthstone Energy, Inc. 
(“Earthstone”) interests. We evaluated 100% of Earthstone’s reserves, which are made up of oil and gas 
properties in New Mexico and Texas. This report utilized an effective date of December 31, 2022, was 
prepared using constant prices and costs, and conforms to Item 1202(a)(8) of Regulation S-K and other rules 
of the Securities and Exchange Commission (“SEC”). This report was prepared for the inclusion as an 
exhibit in a filing made with the SEC. The results of this evaluation are presented in the accompanying 
tabulation, with a composite summary of the values presented below:
Proved
Proved
Developed
Developed
Non-
Proved
Proved
Total
Producing
Producing
Developed
Undeveloped
Proved
Net Reserves
Oil
- Mbbl
 
85,949.3  
2,810.4  
88,759.7  
49,640.7  
138,400.4 
Gas
- MMcf  566,040.0  
8,721.3  574,761.2  
167,404.3  
742,165.6 
NGL
- Mbbl
 
79,008.7  
1,158.8  
80,167.5  
25,673.0  
105,840.5 
Net Revenue
Oil
- M$
 8,229,010.4  271,415.1  8,500,424.7  4,761,062.9  13,261,489.2 
Gas
- M$
 3,131,587.6  
48,121.0  3,179,708.7  
911,800.8  4,091,509.2 
NGL
- M$
 3,092,366.6  
44,865.0  3,137,232.1  1,015,796.4  4,153,027.8 
Severance Taxes
- M$
 925,354.7  
20,238.0  945,592.8  
430,052.0  1,375,644.5 
Ad Valorem Taxes
- M$
 173,641.2  
4,799.9  178,441.1  
67,647.8  
246,088.8 
Operating Expenses
- M$
 3,548,749.0  
62,968.6  3,611,718.0  1,027,049.6  4,638,768.0 
Abandonment Costs
- M$
 
92,177.5  
593.7  
92,771.2  
9,627.7  
102,398.8 
Future Development Costs
- M$
 
0.0  
7,000.0  
7,000.0  1,200,596.6  1,207,596.5 
Future Net Cash Flow (BFIT)
- M$
 9,713,042.4  268,800.9  9,981,840.4  3,953,685.8  13,935,531.0 
Discounted @ 10%
- M$
 5,670,219.3  170,452.1  5,840,672.8  1,948,945.4  7,789,619.2 
Exhibit 99.1
CAWLEY, GILLESPIE & ASSOCIATES, INC.
PETROLEUM CONSULTANTS
13640 BRIARWICK DRIVE, SUITE 100 
306 WEST SEVENTH STREET, SUITE 302 
1000 LOUISIANA STREET, SUITE 1900
AUSTIN, TEXAS 78729-1106 
FORT WORTH, TEXAS 76102-4987 
HOUSTON, TEXAS 77002-5008
512-249-7000 
817- 336-2461 
713-651-9944
www.cgaus.com

Future net revenue is prior to deducting state production taxes and ad valorem taxes. Future net cash 
flow is after deducting these taxes, future capital (development) costs and operating expenses, but before 
consideration of federal income taxes.  In accordance with SEC guidelines, the future net cash flow has been 
discounted at an annual rate of ten percent to determine its “present worth”. The present worth is shown to 
indicate the effect of time on the value of money and should not be construed as being the fair market value 
of the reserves by Cawley, Gillespie & Associates, Inc. (“CG&A”). 
The oil reserves include oil and condensate.  Oil and natural gas liquid (NGL) volumes are expressed 
in barrels (42 U.S. gallons).  Gas volumes are expressed in thousands of standard cubic feet (Mcf) at contract 
temperature and pressure base. 
Hydrocarbon Pricing
As requested for SEC purposes, the base oil and gas prices calculated for December 31, 2022 were 
$93.67/BBL and $6.358/MMBTU, respectively. As specified by the SEC, a company must use a 12-month 
average price, calculated as the unweighted arithmetic average of the first-day-of-the-month price for each 
month within the 12-month period prior to the end of the reporting period. The base oil price is based upon 
WTI-Cushing spot prices (EIA) during January 2022 through December 2022 and the base gas price is based 
upon Henry Hub spot prices (Platts Gas Daily) during January 2022 through December 2022. NGL prices 
were adjusted on a per-property basis and averaged 41.0% of the net oil price on a composite basis. 
The base prices were adjusted for differentials on a per-property basis, which may include local basis 
differential, treating cost, transportation, gas shrinkage, gas heating value (BTU content) and/or crude quality 
and gravity corrections. After these adjustments, the net realized prices for the SEC price case over the life of 
the proved properties was estimated to be $95.82 per barrel for oil, $5.51 per MCF for natural gas and $39.24 
per barrel for NGL. All economic factors were held constant in accordance with SEC guidelines.
Future Development Costs, Expenses and Taxes
Capital expenditures (Future Development Costs), lease operating expenses and ad valorem tax 
values were forecast as provided by Earthstone.  As you explained, the capital costs were based on the most 
current estimates, lease operating expenses were based on the analysis of historical actual expenses, 
operating overhead is included for non-operated properties and no credit or deduction is made for producing 
overhead paid to the company by other owners of the operated properties. Lease operating expenses are 
applied based on location, operatorship and wellbore orientation on a per-property or per-unit basis. Capital 
costs and lease operating expenses were held constant in accordance with SEC guidelines.  
Severance tax rates were applied at normal state percentages of oil and gas revenue. Severance tax 
rates in certain instances, where authorized by taxing authorities, have severance tax abatements and were 
provided by your office and applied when appropriate.
SEC Conformance and Regulations
The reserve classifications and the economic considerations used herein conform to the criteria of the 
SEC as defined in pages 3 and 4 of the Appendix.  The reserves and economics are predicated on regulatory 
agency classifications, rules, policies, laws, taxes and royalties currently in effect except as noted herein. 
Federal, state, and local laws and regulations, which are currently in effect and that govern the development 
and production of oil and natural gas, have been considered in the evaluation of proved reserves for this 
report. The possible effects of changes in legislation or other Federal or State restrictive actions which could 
affect the reserves and economics have not been considered.  These possible changes could have an effect on 
the reserves and economics. However, we do not anticipate nor are we aware of any legislative changes or 
restrictive regulatory actions that may impact the recovery of reserves. 
Earthstone Energy, Inc. Interests - SEC Price Case
January 23, 2023
Page 2

This evaluation includes ten (10) developed non-producing properties, representing “drilled but 
uncompleted” wells anticipated to begin production in early 2023, and 204 proved undeveloped locations, all 
of which are commercial using required SEC pricing. Each of these commercial drilling locations proposed 
as part of Earthstone’s development plans conforms to the proved undeveloped standards as set forth by the 
SEC. In our opinion, Earthstone has indicated it has every intent to complete this development plan as 
scheduled.  Furthermore, Earthstone has demonstrated that it has adequate company staffing, financial 
backing and prior development success to ensure this development plan will be fully executed.
Reserve Estimation Methods
The methods employed in estimating reserves are described on page 2 of the Appendix. Reserves for 
proved developed producing wells were estimated using production performance methods for the vast 
majority of properties. Certain new producing properties with very little production history were forecast 
using a combination of production performance and analogy to similar production, both of which are 
considered to provide a relatively high degree of accuracy. 
Non-producing reserve estimates, including undeveloped properties, were forecast using either 
volumetric or analogy methods, or a combination of both. These methods provide a relatively high degree of 
accuracy for predicting proved undeveloped reserves. The assumptions, data, methods and procedures used 
herein are appropriate for the purpose served by this report.
Miscellaneous
An on-site field inspection of the properties has not been performed nor has the mechanical operation 
or condition of the wells and their related facilities been examined, nor have the wells been tested by Cawley, 
Gillespie & Associates, Inc.  Possible environmental liability related to the properties has not been 
investigated nor considered.  However, the estimated costs of plugging and abandoning wells have been 
included herein as provided.
            The reserve estimates and forecasts were based upon interpretations of data furnished by Earthstone 
and available from our files.  Ownership information and economic factors such as liquid and gas prices, 
price differentials and expenses were furnished by Earthstone.  To some extent, information from public 
records was used to check and/or supplement these data.  The basic engineering and geological data were 
utilized subject to third party reservations and qualifications.  Nothing has come to our attention, however, 
that would cause us to believe that we are not justified in relying on such data. All estimates represent our 
best judgment based on the data available at the time of preparation. Due to inherent uncertainties in future 
production rates, commodity prices and geologic conditions, it should be realized that the reserve estimates, 
the reserves actually recovered, the revenue derived therefrom and the actual cost incurred could be more or 
less than the estimated amounts.
Closing
Cawley, Gillespie & Associates, Inc. is a Texas Registered Engineering Firm (F-693), made up of 
independent registered professional engineers and geologists that have provided petroleum consulting 
services to the oil and gas industry for over 60 years.  This evaluation was supervised by W. Todd Brooker, 
President at Cawley, Gillespie & Associates, Inc. and a State of Texas Licensed Professional Engineer 
(License #83462). We do not own an interest in the properties or Earthstone Energy, Inc. and are not 
employed on a contingent basis.  We have used all methods and procedures that we consider necessary under 
the circumstances to prepare this report. Our work-papers and related data utilized in the preparation of these 
estimates are available in our office.
Earthstone Energy, Inc. Interests - SEC Price Case
January 23, 2023
Page 3

 
 
Yours very truly,
 
 CAWLEY, GILLESPIE & ASSOCIATES, INC.
 
TEXAS REGISTERED ENGINEERING FIRM F-693
    
 
/s/ W. Todd Brooker
W. Todd Brooker, P.E.
President
/s/ Robert P. Bergeron, Jr., P.E.
Robert P. Bergeron, Jr., P.E.
Reservior Engineer
 
 
Earthstone Energy, Inc. Interests - SEC Price Case
January 23, 2023
Page 4

The four methods customarily employed in the estimation of reserves are (1) production performance, (2) material balance, 
(3) volumetric and (4) analogy. Most estimates, although based primarily on one method, utilize other methods depending on the nature 
and extent of the data available and the characteristics of the reservoirs.
Basic information includes production, pressure, geological and laboratory data. However, a large variation exists in the 
quality, quantity and types of information available on individual properties. Operators are generally required by regulatory authorities 
to file monthly production reports and may be required to measure and report periodically such data as well pressures, gas-oil ratios, 
well tests, etc. As a general rule, an operator has complete discretion in obtaining and/or making available geological and engineering 
data. The resulting lack of uniformity in data renders impossible the application of identical methods to all properties, and may result in 
significant differences in the accuracy and reliability of estimates.
A brief discussion of each method, its basis, data requirements, applicability and generalization as to its relative degree of 
accuracy follows:
Production performance. This method employs graphical analyses of production data on the premise that all factors which have 
controlled the performance to date will continue to control and that historical trends can be extrapolated to predict future performance. The 
only information required is production history. Capacity production can usually be analyzed from graphs of rates versus time or 
cumulative production. This procedure is referred to as "decline curve" analysis. Both capacity and restricted production can, in some 
cases, be analyzed from graphs of producing rate relationships of the various production components. Reserve estimates obtained by this 
method are generally considered to have a relatively high degree of accuracy with the degree of accuracy increasing as production 
historyaccumulates.
Material balance. This method employs the analysis of the relationship of production and pressure performance on the premise 
that the reservoir volume and its initial hydrocarbon content are fixed and that this initial hydrocarbon volume and recoveries therefrom can 
be estimated by analyzing changes in pressure with respect to production relationships. This method requires reliable pressure and 
temperature data, production data, fluid analyses and knowledge of the nature of the reservoir. The material balance method is applicable to 
all reservoirs, but the time and expense required for its use is dependent on the nature of the reservoir and its fluids. Reserves for depletion 
type reservoirs can be estimated from graphs of pressures corrected for compressibility versus cumulative production, requiring only data 
that are usually available. Estimates for other reservoir types require extensive data and involve complex calculations most suited to 
computer models which makes this method generally applicable only to reservoirs where there is economic justification for its use. Reserve 
estimates obtained by this method are generally considered to have a degree of accuracy that is directly related to the complexity of the 
reservoir and the quality and quantity of data available.
Volumetric. This method employs analyses of physical measurements of rock and fluid properties to calculate the volume of 
hydrocarbons in-place. The data required are well information sufficient to determine reservoir subsurface datum, thickness, storage 
volume, fluid content and location. The volumetric method is most applicable to reservoirs which are not susceptible to analysis by 
production performance or material balance methods. These are most commonly newly developed and/or no-pressure depleting reservoirs. 
The amount of hydrocarbons in-place that can be recovered is not an integral part of the volumetric calculations but is an estimate inferred 
by other methods and a knowledge of the nature of the reservoir. Reserve estimates obtained by this method are generally considered to 
have a low degree of accuracy; but the degree of accuracy can be relatively high where rock quality and subsurface control is good and the 
nature of the reservoir is uncomplicated.
Analogy. This method, which employs experience and judgment to estimate reserves, is based on observations of similar 
situations and includes consideration of theoretical performance. The analogy method is a common approach used for “resource plays,” 
where an abundance of wells with similar production profiles facilitates the reliable estimation of future reserves with a relatively high 
degree of accuracy. The analogy method may also be applicable where the data are insufficient or so inconclusive that reliable reserve 
estimates cannot be made by other methods. Reserve estimates obtained in this manner are generally considered to have a relatively low 
degree of accuracy.
Much of the information used in the estimation of reserves is itself arrived at by the use of estimates. These estimates are subject 
to continuing change as additional information becomes available. Reserve estimates which presently appear to be correct may be found to 
contain substantial errors as time passes and new information is obtained about well and reservoir performance.
APPENDIX
Methods Employed in the Estimation of Reserves
Appendix
Page 2
Cawley, Gillespie & Associates, Inc.

The Securities and Exchange Commission, in SX Reg. 210.4-10 dated November 18, 1981, as amended on September 19, 
1989 and January 1, 2010, requires adherence to the following definitions of oil and gas reserves:
"(22) Proved oil and gas reserves. Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of 
geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, 
from known reservoirs, and under existing economic conditions, operating methods, and government regulations— prior to the time at 
which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether 
deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the 
operator must be reasonably certain that it will commence the project within a reasonable time.
"(i)      The area of a reservoir considered as proved includes: (A) The area identified by drilling and limited by fluid 
contacts, if any, and (B) Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with 
it and to contain economically producible oil or gas on the basis of available geoscience and engineering data. 
"(ii) In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons 
(LKH) as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower 
contact with reasonable certainty.
"(iii) Where direct observation from well penetrations has defined a highest known oil (HKO) elevation and the potential 
exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if 
geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty.
"(iv)   Reserves which can be produced economically through application of improved recovery techniques (including, but 
not limited to, fluid injection) are included in the proved classification when: (A) Successful testing by a pilot project in an area of the 
reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an 
analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on 
which the project or program was based; and (B) The project has been approved for development by all necessary parties and entities, 
includinggovernmental entities.
"(v) Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be 
determined. The price shall be the average price during the 12-month period prior to the ending date of the period covered by the report, 
determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are 
defined by contractual arrangements, excluding escalations based upon future conditions.
"(6)         Developed oil and gas reserves. Developed oil and gas reserves are reserves of any category that can be 
expected to be recovered:
“(i)      Through existing wells with existing equipment and operating methods or in which the cost of the required 
equipment is relatively minor compared to the cost of a new well; and
“(ii) Through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the 
extraction is by means not involving a well.
"(31) 
 Undeveloped oil and gas reserves. Undeveloped oil and gas reserves are reserves of any category that are 
expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required 
for recompletion.
“(i) Reserves on undrilled acreage shall be limited to those directly offsetting  development spacing  areas  that  are 
reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of 
economic producibility at greater distances.
“(ii) Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted 
indicating that they are scheduled to be drilled within five years, unless the specific circumstances, justify a longer time.
“(iii) Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage  for  which  an 
application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective 
by actual projects in the same reservoir or an analogous reservoir, as defined in paragraph (a)(2) of this section, or by other evidence 
using reliable technology establishing reasonable certainty.
APPENDIX
Reserve Definitions and Classifications
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"(18)
Probable reserves. Probable reserves are those additional reserves that are less certain to be recovered than 
proved reserves but which, together with proved reserves, are as likely as not to be recovered.
“(i)  When deterministic methods are used, it is as likely as not that actual remaining quantities recovered will exceed the 
sum of estimated proved plus probable reserves. When probabilistic methods are used, there should be at least a 50% probability that the 
actual quantities recovered will equal or exceed the proved plus probable reserves estimates. 
“(ii) Probable reserves may be assigned to areas of a reservoir adjacent to proved reserves where data control or 
interpretations of available data are less certain, even if the interpreted reservoir continuity of structure or productivity does not meet the 
reasonable certainty criterion. Probable reserves may be assigned to areas that are structurally higher than the proved area if these areas 
are in communication with the proved reservoir. 
“(iii)    Probable reserves estimates also include potential incremental quantities associated with a greater percentage 
recovery of the hydrocarbons in place than assumed for proved reserves. 
“(iv)
See also guidelines in paragraphs (17)(iv) and (17)(vi) of this section (below).
reserves.
"(17) 
Possible reserves. Possible reserves are those additional reserves that are less certain to be recovered than 
probable
“(i) 
When deterministic methods are used, the total quantities ultimately recovered from a project have a low 
probability of exceeding proved plus probable plus possible reserves. When probabilistic methods are used, there should be at least a 
10% probability that the total quantities ultimately recovered will equal or exceed the proved plus probable plus possible reserves 
estimates.
“(ii) Possible reserves may be assigned to areas of a reservoir adjacent to probable reserves where data control and 
interpretations of available data are progressively less certain. Frequently, this will be in areas where geoscience and engineering data 
are unable to define clearly the area and vertical limits of commercial production from the reservoir by a defined project.
“(iii)    Possible reserves also include incremental quantities associated with a greater percentage recovery of the 
hydrocarbons in place than the recovery quantities assumed for probable reserves.
“(iv) The proved plus probable and proved plus probable plus possible reserves estimates must be based on reasonable 
alternative technical and commercial interpretations within the reservoir or subject project that are clearly documented, including 
comparisons to results in successful similar projects.
“(v) Possible reserves may be assigned where geoscience and engineering data identify directly adjacent portions of a 
reservoir within the same accumulation that may be separated from proved areas by faults with displacement less than formation 
thickness or other geological discontinuities and that have not been penetrated by a wellbore, and the registrant believes that such 
adjacent portions are in communication with the known (proved) reservoir. Possible reserves may be assigned to areas that are 
structurally higher or lower than the proved area if these areas are in communication with the proved reservoir.
“(vi) Pursuant to paragraph (22)(iii) of this section (above), where direct observation has defined a highest known oil 
(HKO) elevation and the potential exists for an associated gas cap, proved oil reserves should be assigned in the structurally higher 
portions of the reservoir above the HKO only if the higher contact can be established with reasonable certainty through reliable 
technology. Portions of the reservoir that do not meet this reasonable certainty criterion may be assigned as probable and possible oil or 
gas based on reservoir fluid properties and pressure gradient interpretations.”
Instruction 4 of Item 2(b) of Securities and Exchange Commission Regulation S-K was revised January 1, 2010 to state that 
"a registrant engaged in oil and gas producing activities shall provide the information required by Subpart 1200 of Regulation S-K." 
This is relevant in that Instruction 2 to paragraph (a)(2) states: “The registrant is permitted, but not required, to disclose probable or 
possible reserves pursuant to paragraphs (a)(2)(iv) through (a)(2)(vii) of this Item.”
"(26) Reserves. Reserves are estimated remaining quantities of oil and gas and related substances anticipated to be 
economically producible, as of a given date, by application of development projects to known accumulations. In addition, there must 
exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, 
installed means of delivering oil and gas or related substances to market, and all permits and financing required to implement the 
project.
“Note to paragraph (26): Reserves should not be assigned to adjacent reservoirs isolated by major, potentially sealing, faults until those 
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reservoirs are penetrated and evaluated as economically producible. Reserves should not be assigned to areas that are clearly separated 
from a known accumulation by a non-productive reservoir (i.e., absence of reservoir, structurally low reservoir, or negative test results). 
Such areas may contain prospective resources (i.e., potentially recoverable resources from undiscovered accumulations).”
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