EDGAR 10-K Filing

Company CIK: 10254
Filing Year: 2023
Filename: 10254_10-K_2023_0000010254-23-000058.json

---

ITEM 1. BUSINESS
Item 1. Business
Overview
Earthstone Energy, Inc., a Delaware corporation (“Earthstone” and together with our consolidated subsidiaries, the “Company,” “our,” “we,” “us,” or similar terms), is a growth-oriented independent oil and gas company engaged in the acquisition and development of oil and gas reserves through activities that include 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.
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
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.
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.
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
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
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.
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
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
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
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
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
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
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
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,
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.
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:
•A culture of empowerment, transparency, and cooperation is embraced
•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
•Conflict is addressed early and productively
•Professional and personal development is encouraged
•Teamwork is fostered
•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
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.
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
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;
•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
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.
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.
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
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.
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
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
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.
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
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
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
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
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.
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.
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;
•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
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.
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
Item 1B. Unresolved Staff Comments
None.

---

ITEM 2. PROPERTIES
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 $530.6 million in capital expenditures, primarily drilling and completion costs. We expect to further develop our properties through additional drilling.
2022 Activity in Proved Reserves
From January 1, 2022 to December 31, 2022, our total estimated proved reserves increased 149% from 147,587 MBoe to 367,936 MBoe. Of that, estimated proved developed reserves increased 183% from 93,575 MBoe to 264,721 MBoe and estimated proved undeveloped reserves increased 91% from 54,012 MBoe to 103,215 MBoe. The most significant increase in our total estimated proved reserves resulted from purchases of minerals in place resulting from the Chisholm Acquisition, Bighorn Acquisition and Titus Acquisition, all completed in 2022.
Proved Reserves as of December 31, 2022
The below table sets forth a summary of our estimated crude oil, natural gas and natural gas liquid reserves as of December 31, 2022, based on the annual reserve estimate prepared by CG&A. In preparing this reserve report, CG&A evaluated 100% of our properties at December 31, 2022. The prices used in estimating proved reserves are based on the unweighted arithmetic average of the first-day-of-the-month price for each month within the 12-month period for the year. All prices and costs associated with operating wells were held constant in accordance with the SEC guidelines.
Our proved reserve categories as of December 31, 2022 are summarized in the table below:
Oil
(MBbl) Natural Gas
(MMcf) Natural Gas Liquids
(MBbl) Total
(MBoe)(2)
% of Total
Proved Undiscounted Future Net Cash Flows
($ 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
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.
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
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.
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.
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.
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
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
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 DISCLOSURE
Item 4. Mine Safety Disclosures
Not applicable.
PART II

---

ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY
Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
Market Information
Shares of our Class A Common Stock are listed on the NYSE under the symbol “ESTE.”
Holders
As of March 1, 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.

---

ITEM 6. SELECTED FINANCIAL DATA
Item 6. Reserved

---

ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations
This discussion and other items in this Annual Report on Form 10-K contain forward-looking statements and information that are based on management’s beliefs, as well as assumptions made by, and information currently available to, management. When used in this document, the words “believe,” “anticipate,” “estimate,” “expect,” “intend,” “may,” “will,” “project,” “forecast,” “plan,” “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
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.
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).
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.
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.
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.
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
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.
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.
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
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
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
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.
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
Item 8. Financial Statements and Supplementary Data
See Index to Consolidated Financial Statements and Supplementary Information on Page.

---

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

---

ITEM 9A. CONTROLS AND PROCEDURES
Item 9A. Controls and Procedures
Internal Control Over Financial Reporting
Evaluation of Disclosure Controls and Procedures
(a) Disclosure Controls and Procedures
We maintain disclosure controls and procedures that are designed to provide reasonable assurance that information required to be disclosed by us in the reports that we file or submit to the SEC under the Exchange Act, is recorded, processed, summarized and reported within the time periods specified by the SEC’s rules and forms, and that information is accumulated and communicated to our management, including our Chief Executive Officer and Principal Accounting Officer, as appropriate to allow timely decisions regarding required disclosure.
In accordance with Rules 13a-15(b) and 15d-15(b) under the Exchange Act, we carried out an evaluation, under the supervision and with the participation of management, including our Chief Executive Officer and Principal Accounting Officer, of the effectiveness of our disclosure controls and procedures (as defined by Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of the end of the period covered by this Annual Report on Form 10-K. As described below under paragraph (b) within Management’s Annual Report on Internal Control over Financial Reporting, our Chief Executive Officer and Principal Accounting Officer have concluded that, as of the end of the period covered by this Annual Report on Form 10-K, our disclosure controls and procedures were effective to provide reasonable assurance that information required to be disclosed by us in the reports that we file or submit to the SEC under the Exchange Act is recorded, processed, summarized and reported within the time periods specified by the SEC’s rules and that such information is accumulated and communicated to our management, including our Chief Executive Officer and Principal Accounting Officer, as appropriate to allow timely decisions regarding required disclosure.
The audit report of our independent registered public accounting firm, which is included in this Annual Report on Form 10-K, expressed an unqualified opinion on our consolidated financial statements.
(b) Management’s Annual Report on Internal Control over Financial Reporting
Our management is responsible for establishing and maintaining adequate internal control over financial reporting as defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act. Our internal control over financial reporting is designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. Our internal control over financial reporting includes those policies and procedures that:
•pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect our transactions and dispositions of our assets;
•provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that our receipts and expenditures are being made only in accordance with authorizations of our management; and
•provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of our assets that could have a material effect on the financial statements.
While “reasonable assurance” is a high level of assurance, it does not mean absolute assurance. Because of its inherent limitations, internal control over financial reporting may not prevent or detect every misstatement and instance of fraud. Controls are susceptible to manipulation, especially in instances of fraud caused by collusion of two or more people. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
Under the supervision and with the participation of our Chief Executive Officer and Principal Accounting Officer, our management conducted an evaluation of the effectiveness of our internal control over financial reporting as of December 31, 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.
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
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.

---

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

---

ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
Item 10. Directors, Executive Officers and Corporate Governance
See list of “Information about our Executive Officers” under Item 1 of this report, which is incorporated herein by reference.
The other information required by this item is incorporated herein by reference to the Proxy Statement, which will be filed with the SEC not later than 120 days subsequent to December 31, 2022.

---

ITEM 11. EXECUTIVE COMPENSATION
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
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
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 ACCOUNTING FEES AND SERVICES
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.
PART IV

---

ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES
Item 15. Exhibit and Financial Statement Schedules
Incorporated by Reference
Exhibit
No. Description Form SEC File No. Exhibit Filing Date Filed
Herewith Furnished
Herewith
2.1 Contribution Agreement dated November 7, 2016, by and among Earthstone Energy, Inc., Earthstone Energy Holdings, LLC, Lynden USA Inc., Lynden USA Operating, LLC, Bold Energy Holdings, LLC and Bold Energy III LLC.
8-K 001-35049 2.1 November 8, 2016
2.1(a) First Amendment to the Contribution Agreement dated March 21, 2017, by and among Earthstone Energy, Inc., Earthstone Energy Holdings, LLC, Lynden USA Inc., Lynden USA Operating, LLC, Bold Energy Holdings, LLC and Bold Energy III LLC.
8-K 001-35049 2.1 March 23, 2017
2.2 Purchase and Sale Agreement dated as of December 17, 2020, by and among Earthstone Energy, Inc., Earthstone Energy Holdings, LLC, Independence Resources Holdings, LLC and Independence Resources Manager, LLC.
8-K 001-35049 2.1 December 22, 2020
2.3 Purchase and Sale Agreement dated March 31, 2021, among Tracker Resource Development III, LLC, TRD III Royalty Holdings (TX), LP, Earthstone Energy, Inc. and Earthstone Energy Holdings, LLC.
8-K 001-35049 2.1 April 5, 2021
2.4 Purchase and Sale Agreement dated March 31, 2021, among SEG-TRD LLC, SEG-TRD II LLC, Earthstone Energy, Inc. and Earthstone Energy Holdings, LLC.
8-K 001-35049 2.2 April 5, 2021
2.5 Purchase and Sale Agreement dated as of September 30, 2021, by and among Earthstone Energy, Inc., Earthstone Energy Holdings, LLC, and Foreland Investments LP.
8-K 001-35049 2.1 October 4, 2021
2.6 Purchase and Sale Agreement dated as of September 30, 2021, by and among Earthstone Energy, Inc., Earthstone Energy Holdings, LLC, and BCC-Foreland LLC.
8-K 001-35049 2.2 October 4, 2021
2.7 Purchase and Sale Agreement dated December 15, 2021, by and between Chisholm Energy Operating, LLC, Chisholm Energy Agent, Inc., Earthstone Energy, Inc., and Earthstone Energy Holdings, LLC.
8-K 001-35049 2.1 December 17, 2021
2.8 Purchase and Sale Agreement dated January 30, 2022, by and among Bighorn Asset Company, LLC, Earthstone Energy, Inc. and Earthstone Energy Holdings, LLC.
8-K 001-35049 2.1 February 2, 2022
2.9 Purchase and Sale Agreement dated June 27, 2022, by and among Titus Oil & Gas Production, LLC, Titus Oil & Gas Corporation, Lenox Minerals, LLC and Lenox Mineral Title Holdings, Inc, collectively, as Seller, and Earthstone Energy Holdings, LLC, as purchaser, and Earthstone Energy, Inc.
8-K 001-35049 2.1 June 29, 2022
2.10 Purchase and Sale Agreement dated June 27, 2022, by and among Titus Oil & Gas Production II, LLC, Lenox Minerals II, LLC and Lenox Mineral Holdings II, LLC, collectively, as Seller and Earthstone Energy Holdings, LLC, as Purchaser and Earthstone Energy, Inc.
8-K 001-35049 2.2 June 29, 2022
3.1 Third Amended and Restated Certificate of Incorporation of Earthstone Energy, Inc. dated May 9, 2017.
8-A 001-35049 3.1 May 9, 2017
3.1(a) Certificate of Amendment to the Third Amended and Restated Certificate of Incorporation of Earthstone Energy, Inc. dated July 20, 2021.
8-K 001-35049 3.1 July 23, 2021
3.2 Amended and Restated Bylaws of Earthstone Energy, Inc. dated February 26, 2010.
8-K 001-35049 3(ii) March 3, 2010
3.2(a) First Amendment to the Amended and Restated Bylaws of Earthstone Energy, Inc. dated November 22, 2011.
8-K 001-35049 3(ii)c November 23, 2011
3.2(b) Second Amendment to the Amended and Restated Bylaws of Earthstone Energy, Inc. dated October 22, 2015.
8-K 001-35049 3.2 October 26, 2015
3.3 Certificate of Designation, Preferences, Rights and Limitations of the Series A Convertible Preferred Stock.
8-K 001-35049 3.1 April 18, 2022
3.4 Certificate of Elimination of Series A Convertible Preferred Stock.
8-K 001-35049 3.1 July 15, 2022
4.1 Specimen Class A Common Stock Certificate of Earthstone Energy, Inc.
8-K 001-35049 4.1 May 15, 2017
4.2 Description of Earthstone Energy, Inc.’s Class A Common Stock.
10-K 001-35049 4.2 March 11, 2020
4.3 Indenture, dated as of April 12, 2022, by and among Earthstone Energy Holdings, LLC, Earthstone Energy, Inc., Earthstone Operating, LLC, Earthstone Permian LLC, Sabine River Energy, LLC, Independence Resources Technologies, LLC, and U.S. Bank Trust Company, National Association, as Trustee.
8-K 001-35049 4.1 April 13, 2022
10.1† Earthstone Energy, Inc. 2014 Long-Term Incentive Plan.
8-K 001-35049 10.3 December 29, 2014
10.1(a)† First Amendment to the Earthstone Energy, Inc. 2014 Long-Term Incentive Plan dated October 22, 2015.
8-K 001-35049 10.1 October 26, 2015
10.1(b)† Second Amendment to the Earthstone Energy, Inc. 2014 Long-Term Incentive Plan dated May 9, 2017.
8-K 001-35049 10.6 May 15, 2017
10.2 Form of Indemnification Agreement.
8-K 001-35049 10.5 December 29, 2014
10.5 Second Amended and Restated Limited Liability Company Agreement of Earthstone Energy Holdings, LLC dated April 18, 2022.
8-K 001-35049 10.6 April 18, 2022
10.6 Registration Rights Agreement dated May 9, 2017 between Earthstone Energy, Inc. and Bold Energy Holdings, LLC.
8-K 001-35049 10.3 April 18, 2022
10.9† Amended and Restated 2014 Long Term Incentive Plan dated June 6, 2018.
8-K 001-35049 10.1 June 6, 2018
10.9(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
10.12(f) Amended and Restated Fifth Amendment to Credit Agreement dated as of January 30, 2022, among Earthstone Energy Holdings, LLC, as Borrower, Earthstone Energy, Inc., as Parent, Wells Fargo Bank, National Association, as Administrative Agent, the lenders and guarantors party thereto.
8-K 001-35049 10.1 February 2, 2022
10.12(g) Sixth Amendment to Credit Agreement dated as of June 2, 2022, by and among Earthstone Energy Holdings, LLC, as Borrower, Earthstone Energy, Inc., as Parent, Wells Fargo Bank, National Association as Administrative Agent, and the Lenders and guarantors party thereto.
8-K 001-35049 10.1 June 2, 2022
10.12(h) Seventh Amendment to Credit Agreement dated as of August 10, 2022, by and among Earthstone Energy Holdings, LLC, as Borrower, Earthstone Energy, Inc., as Parent, Wells Fargo Bank, National Association as Administrative Agent, and the Lenders and guarantors party thereto.
8-K 001-35049 10.3 August 11, 2022
10.13† Form of Performance Unit Agreement (Executive Management).
8-K 001-35049 10.1 January 31, 2020
10.14† Form of Restricted Stock Unit Agreement (Executive Management).
8-K 001-35049 10.2 January 31, 2020
10.15† Form of Restricted Stock Unit Agreement (Director).
8-K 001-35049 10.3 January 31, 2020
10.16 Registration Rights Agreement dated January 7, 2021, by and among Earthstone Energy, Inc., Independence Resources Holdings, LLC and the Persons identified on Schedule I thereto.
8-K 001-35049 10.1 January 13, 2021
10.19† Form of Performance Unit Agreement (Executive Management).
8-K 001-35049 10.1 January 29, 2021
10.21 Registration Rights Agreement dated July 20, 2021, by and among Earthstone Energy, Inc., Tracker Resource Development III, LLC, EnCap Energy Capital Fund VIII, L.P., ZIP Ventures I, L.L.C, and Tracker III Holdings, LLC.
8-K 001-35049 10.1 July 23, 2021
10.22 Registration Rights Agreement dated July 20, 2021, by and among Earthstone Energy, Inc., SEG-TRD LLC, and SEG-TRD II LLC.
8-K 001-35049 10.2 July 23, 2021
10.25 Registration Rights Agreement dated November 2, 2021, by and among Earthstone Energy, Inc., Foreland Investments LP, the parties listed on Schedule I thereto, and the Persons identified on Schedule II thereto.
8-K 001-35049 10.1 November 2, 2021
10.26 Form of Lock-up Agreement.
8-K 001-35049 10.2 November 2, 2021
10.27 Securities Purchase Agreement dated as of January 30, 2022, by and among Earthstone Energy, Inc. and the purchasers set forth therein.
8-K 001-35049 10.2 February 2, 2022
10.28 Registration Rights Agreement dated February 15, 2022 by and among Earthstone Energy, Inc., Chisholm Energy Operating, LLC, and Chisholm Energy Holdings, LLC.
8-K 001-35049 10.1 February 18, 2022
10.29 Form of Lock-up Agreement.
8-K 001-35049 10.2 February 18, 2022
10.30 Amended and Restated Voting Agreement dated February 15, 2022, by and among Earthstone Energy, Inc., EnCap Investments L.P., Warburg Pincus Private Equity (E&P) XI - A, L.P., Warburg Pincus XI (E&P) Partners - A, L.P., WP IRH Holdings, L.P., Warburg Pincus XI (E&P) Partners - B IRH, LLC, Warburg Pincus Energy (E&P)-A, LP, Warburg Pincus Energy (E&P) Partners-A, LP, Warburg Pincus Energy (E&P) Partners-B IRH, LLC, WP Energy Partners IRH Holdings, L.P., and WP Energy IRH Holdings, L.P., WP Energy Chisholm Holdings, L.P., WP Energy Partners Chisholm Holdings, L.P., Warburg Pincus Energy (E&P) Partners-B Chisholm, LLC, Warburg Pincus Private Equity (E&P) XII (A), L.P., WP XII Chisholm Holdings, L.P., Warburg Pincus XII (E&P) Partners-2 Chisholm, LLC, Warburg Pincus Private Equity (E&P) XII-D (A), L.P., Warburg Pincus Private Equity (E&P) XII-E (A), L.P., Warburg Pincus XII (E&P) Partners-1, L.P., and WP XII (E&P) Partners (A), L.P.
8-K 001-35049 10.3 February 18, 2022
10.30(a) First Amendment to Amended and Restated Voting Agreement dated August 1, 2022, by and among Earthstone Energy, Inc., Warburg Pincus Private Equity (E&P) XI-A, L.P., Warburg Pincus XI (E&P) Partners-A, L.P., WP IRH Holdings, L.P., Warburg Pincus XI (E&P) Partners-B IRH, LLC, Warburg Pincus Energy (E&P)-A, L.P., Warburg Pincus Energy (E&P) Partners-A, L.P., Warburg Pincus Energy (E&P) Partners-B IRH, LLC, WP Energy Partners IRH Holdings, L.P., WP Energy IRH Holdings, L.P., WP Energy Chisholm Holdings, L.P., WP Energy Partners Chisholm Holdings, L.P., Warburg Pincus Energy (E&P) Partners-B Chisholm, LLC, Warburg Pincus Private Equity (E&P) XII (A), L.P., WP XII Chisholm Holdings, L.P., Warburg Pincus XII (E&P) Partners-2 Chisholm, LLC, Warburg Pincus Private Equity (E&P) XII-D (A), L.P., Warburg Pincus Private Equity (E&P) XII-E (A), L.P., Warburg Pincus XII (E&P) Partners-1, L.P., and WP XII (E&P) Partners (A), L.P., and EnCap Investments L.P.
8-K 001-35049 10.1 August 1, 2022
10.31 Purchase Agreement dated as of April 7, 2022, by and among Earthstone Energy Holdings, LLC, Earthstone Energy, Inc., Earthstone Operating, LLC, Earthstone Permian LLC, Sabine River Energy, LLC, Independence Resources Technologies, LLC, and RBC Capital Markets, LLC, as representative of the initial purchasers named therein.
8-K 001-35049 10.1 April 13, 2022
10.32 Registration Rights Agreement dated April 14, 2022, by and among Earthstone Energy, Inc. and Bighorn Permian Resources, LLC.
8-K 001-35049 10.2 April 18, 2022
10.33 Registration Rights Agreement dated April 14, 2022, by and among Earthstone Energy, Inc., EnCap Energy Capital Fund XI, L.P. and Cypress Investments, LLC.
8-K 001-35049 10.3 April 18, 2022
10.34 Lock-up Agreement dated April 14, 2022, by and between Earthstone Energy, Inc. and Bighorn Permian Resources, LLC.
8-K 001-35049 10.4 April 18, 2022
10.35 Voting Agreement dated as of April 14, 2022, by and among Earthstone Energy, Inc., Cypress Investments, LLC, EnCap Investments L.P., Warburg Pincus Private Equity (E&P) XI-A, L.P., Warburg Pincus XI (E&P) Partners-A, L.P., WP IRH Holdings, L.P., Warburg Pincus XI (E&P) Partners-B IRH, LLC, Warburg Pincus Energy (E&P)-A, L.P., Warburg Pincus Energy (E&P) Partners-A, L.P., Warburg Pincus Energy (E&P) Partners-B IRH, LLC, WP Energy Partners IRH Holdings, L.P., WP Energy IRH Holdings, L.P., WP Energy Chisholm Holdings, L.P., WP Energy Partners Chisholm Holdings, L.P., Warburg Pincus Energy (E&P) Partners-B Chisholm, LLC, Warburg Pincus Private Equity (E&P) XII (A), L.P., WP XII Chisholm Holdings, L.P., Warburg Pincus XII (E&P) Partners-2 Chisholm, LLC, Warburg Pincus Private Equity (E&P) XII-D (A), L.P., Warburg Pincus Private Equity (E&P) XII-E (A), L.P., Warburg Pincus XII (E&P) Partners-1, L.P., and WP XII (E&P) Partners (A), L.P.
8-K 001-35049 10.5 April 18, 2022
10.36 Registration Rights Agreement dated August 10, 2022, by and among Earthstone Energy, Inc., Titus Oil & Gas, LLC, and Titus Oil & Gas Investments II, LLC.
8-K 001-35049 10.1 August 11, 2022
10.37 Form of Lock-up Agreement.
8-K 001-35049 10.2 August 11, 2022
10.38† Form of Performance Unit Agreement (Annualized TSR).
8-K 001-35049 10.1 January 12, 2023
10.39† Form of Performance Unit Agreement (Relative TSR).
8-K 001-35049 10.2 January 12, 2023
10.40† Form of Restricted Stock Unit Agreement.
8-K 001-35049 10.3 January 12, 2023
10.41† Form of Restricted Stock Unit Agreement (non-employee director).
8-K 001-35049 10.4 January 12, 2023
14.1 Code of Business Conduct and Ethics.
X
21.1 List of Subsidiaries.
X
23.1 Consent of Cawley, Gillespie & Associates, Inc.
X
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.