Items 1 and 2. Business and Properties
Overview
Riley Permian is a growth-oriented, independent oil and natural gas company focused on the acquisition, exploration, development and production of oil, natural gas and NGLs in Texas and New Mexico. Our activities primarily target the horizontal development of the San Andres formation, a shelf margin deposit on the Northwest Shelf of the Permian Basin. The majority of our acreage is located on large, contiguous blocks in Yoakum County, Texas (the "Champions Assets").
We were formed as a Delaware limited liability company, Riley Exploration – Permian, LLC ("REP LLC"), in 2016. On February 26, 2021 (the “Closing Date”), Riley Exploration Permian, Inc., a Delaware corporation (f/k/a Tengasco, Inc. (“Tengasco”)), consummated a merger pursuant to that certain Agreement and Plan of Merger (“Merger Agreement”), dated as of October 21, 2020, by and among Tengasco, Antman Sub, LLC, a newly formed Delaware limited liability company and wholly-owned subsidiary of Tengasco (“Merger Sub”), and REP LLC, as amended by Amendment No. 1 to Agreement and Plan of Merger, dated as of January 20, 2021, by and among Tengasco, Merger Sub and REP LLC. Pursuant to the terms of the Merger Agreement, a business combination between Tengasco and REP LLC was effected through the merger of Merger Sub with and into REP LLC, with REP LLC as the surviving company and as a wholly-owned subsidiary of Tengasco (collectively, with the other transactions described in the Merger Agreement, the “Merger”). On the Closing Date, Tengasco changed its name to Riley Exploration Permian, Inc. Our organizational structure includes wholly-owned consolidated subsidiaries through which our operations are conducted, including without limitation, REP LLC and Riley Permian Operating Company, LLC.
The Merger was accounted for as a reverse merger and, as such, REP LLC is considered the Company’s accounting predecessor and its historical operations are deemed to be those of the Company.
On August 16, 2022, the Company's Board of Directors (the "Board") acting by written consent resolved to amend and restate the Company's Second Amended and Restated Bylaws to change the Company's fiscal year period from October 1st through September 30th each year to January 1st through December 31st each year commencing with the 2022 calendar year (the "Bylaws Restatement"). On August 19, 2022, the holders of approximately 75% of our outstanding Common Stock acting by written consent approved the Bylaws Restatement and adopted the Third Amended and Restated Bylaws. In accordance with Rule 14c-2 under the Exchange Act, the aforementioned actions taken by written consent became effective on September 23, 2022. As a result, the Company's 2022 fiscal year was the period from January 1, 2022 to December 31, 2022.
Acquisition in 2023
On February 22, 2023, the Company entered into a purchase and sale agreement (the "Purchase Agreement") to acquire interests in oil and natural gas leases and related property with Pecos Oil & Gas, LLC (“Pecos”) for a purchase price of approximately $330 million, subject to customary closing adjustments, (the “New Mexico Acquisition”). The oil and natural gas leases are located in the Yeso trend of the Permian Basin in Eddy County of New Mexico. On February 22, 2023, in connection with the Purchase Agreement, REP deposited $33 million in cash into a third party escrow account, which will be credited against the purchase price upon closing. See Note 15 - Subsequent Events for further discussion. In connection with the Purchase Agreement, the Company entered into a commitment letter dated February 22, 2023 (the "Commitment Letter") with EOC Partners Advisors L.P. and/or one of its affiliates (collectively, "EOC") in which EOC and/or one of its affiliates will purchase $200 million of unsecured senior notes ("Senior Notes") from the Company as of the closing date of the New Mexico Acquisition. The proceeds of the Senior Notes will be used to fund a portion of the purchase price of the New Mexico Acquisition and to pay fees, costs and expenses related to the New Mexico Acquisition and the related financing transactions. The funding of the Senior Notes is contingent on the satisfaction or waiver of certain conditions set forth in the Commitment Letter. See Note 15 - Subsequent Events for further discussion.
Developments in 2022
EOR Project. The Company continued development of its EOR project, which seeks to lower decline rates and ultimately increase recovery of oil by injecting a combination of water and CO2 through vertical wells, applied to horizontal producing wells in Yoakum County, Texas (the "EOR Project"). These wells are directly adjacent to several of the largest EOR projects in the U.S., which have employed EOR techniques for many decades. See "—Development Opportunities" below for additional information.
Market Conditions, Commodity Prices and Interest Rates. Commodity prices experienced exceptional volatility during 2022 due to ongoing geopolitical events and fluctuating supply/demand factors. In addition, global markets experienced supply shortages and corresponding significant inflation across a wide variety of products, services and wages. As a result, the U.S. Federal Reserve and other international central banks began tightening monetary policies during 2022, including increasing short-term borrowing rates. This changing monetary policy has impacted credit and capital markets with generally increased costs of borrowing and heightened volatility in capital markets.
Our Business Strategy
Our strategy is to create and deliver long-term shareholder value through the following:
•Steadily grow cash flow from operations through development of our existing assets and continuous improvement of our operating capabilities. We intend to grow our production and reserves through development of our multi-year drilling inventory, which we believe offers economically attractive investment opportunities in the current environment. We believe such growth and corresponding increase in scale can lead to operating cost efficiencies and may further expand margins. Our management, operating and technical teams strive to continually improve our operating capabilities and cost structure, with an objective of reducing per unit costs and enhancing returns. We seek to grow within the limits of conservative capital allocation, often reinvesting less than our operating cash flows.
•Identify attractive new opportunities for capital investment. Our business produces one of the most highly demanded and valuable commodities in the world, which society uses across many fundamental aspects of everyday life. We believe investing in oil and natural gas assets continues to represent an attractive opportunity. Concurrently, we acknowledge a growing discussion for decarbonizing economies and the associated potential impacts on our business. We believe opportunities may arise in the oil and natural gas business as capital allocation priorities shift at some larger oil and natural gas companies, or restrict at other oil and natural gas companies, potentially providing for value-creating opportunities for Riley Permian. We believe our business could benefit from increased scale, and we will seek out attractive merger and acquisition opportunities. Further, we believe it is prudent to monitor the transitioning energy landscape and identify arising investment opportunities in which the Company may have competitive strengths and opportunities. One example of such potential opportunity includes the Company’s investigative efforts into carbon capture, utilization and sequestration ("CCUS") projects, for which we believe we may be well-positioned based on the characteristics of our assets.
•Distribute excess returns to stockholders in the form of dividends. We believe we can often grow production and cash flow in excess of required capital and operating costs. We believe that distributing a meaningful portion of our cash generated by operating activities provides stockholders the combination of a current return and increased certainty for a portion of long-term value. Because the oil and natural gas business is capital intensive, and because we recognize many benefits of growth, management will strive to seek an appropriate balance of reinvesting for growth versus other capital allocation choices, such as reducing debt or returning capital back to stockholders.
Our Competitive Strengths
We believe that the following strengths will allow us to successfully execute our business strategies:
•Proven and incentivized management team with substantial expertise and long-term perspective. Our executive team has a proven track record of operating and managing oil and natural gas companies across industry cycles. We have successfully managed development programs across various basins, including significant experience in the Northwest Shelf region of the Permian Basin, among other basins. Our Chief Executive Officer, Bobby Riley, was one of the original designers of systems for down-hole data acquisition in gravel pack and frack pack operations and has more than 40 years of experience in the independent oil and natural gas sector. We believe the executive management team has a vested and aligned interest in creating value for stockholders, with equity ownership in the Company. Management prioritizes corporate sustainability, including positioning the Company for success in both the near-term and long-term with initiatives focused on existing business and the transitioning energy landscape.
•Premier, low-decline asset in one of North America’s leading oil resource plays. Our acreage is primarily characterized by a multi-year, oil-weighted inventory of horizontal drilling locations that we believe provides attractive growth and return opportunities. We believe that investments in our core assets are capable of producing returns that are competitive with many of the top-performing oil and natural gas basins in the U.S. We believe this positions our business to perform well across a range of commodity price environments. Further, the conventional nature of the San Andres, the producing reservoir of our core assets, allows for a lower base decline rate as compared to most
unconventional or shale basins in the U.S. A lower base decline rate leads to less new production needed in order to maintain or grow production.
•High degree of operational control. We control, and intend to maintain control, of a substantial majority of our producing properties and drilling inventory. We believe this practice best leverages the experience of our management and technical teams and can lead to improvements in our operating cost structure, selection of drilling and completion techniques, greater flexibility to react to market changes and overall enhanced long-term returns. We also made the strategic decision to own and operate the salt water disposal systems and electricity distribution infrastructure necessary to support operations. This has allowed us to significantly reduce our operating costs and keep pace with our expected development program.
•Financial flexibility. We strive to maintain financial flexibility that will allow us to execute our business strategies on existing and potentially new businesses. We expect to continue our oil and natural gas development activities by funding the majority of capital expenditures with operating cash flow. From time to time we may seek outside sources of capital for acquisitions and new ventures. As of December 31, 2022, the borrowing base of our revolving credit facility was $225 million and we had $169 million available for borrowing. We also have the ability to scale up or drawback on our commodity hedging program that seeks to reduce our exposure to downside commodity price fluctuations as part of our maintenance of a conservative financial management program.
Our Properties
As of December 31, 2022, we had approximately 30,470 net acres and a total of 100 net producing wells. We operated 93% of our net production for the year ended December 31, 2022, and have an average working interest of 95% in our operated wells. Our average net daily production during the year ended December 31, 2022 was approximately 11,505 Boe/d.
Our acreage is primarily located on large contiguous blocks in Yoakum County, Texas with additional acreage located in Lea and Roosevelt Counties, New Mexico. Riley Permian’s acreage in Yoakum County offsets legacy Permian Basin San Andres fields, including the Wasson and Brahaney Fields, which have produced more than 2.1 billion barrels of oil equivalent and 108 million barrels of oil equivalent, respectively, from the San Andres Formation since development in the area began in the 1930’s and 1940’s. Based on the close proximity to these productive fields, combined with the horizontal San Andres wells we have drilled to date and the wells drilled by offset operators, we believe we have significantly delineated our acreage.
The Permian Basin is an oil and natural gas producing area located in West Texas and the adjoining area of southeastern New Mexico covering an area approximately 250 miles wide and 300 miles long, and encompasses several sub-basins, including the Delaware Basin, Midland Basin, Central Basin Platform and Northwest Shelf. The San Andres Formation is a shelf margin deposit composed of dolomitized carbonates.
Oil, Natural Gas and NGL Reserves
Summary of Oil, Natural Gas and NGL Reserves
The following table summarizes the Company's estimated proved reserves as of December 31, 2022, September 30, 2021, and September 30, 2020 based on the reserve reports prepared by NSAI in accordance with rules and regulations of the SEC.
| | | | | | | | | | | | | | | | | | | | |
| | December 31, | | September 30, |
| | 2022 | | 2021 | | 2020 |
Proved Developed Producing Reserves:(1) | | | | | | |
| Oil (MBbls) | | 29,632 | | 25,820 | | 19,149 |
| Natural Gas (MMcf) | | 59,314 | | 45,712 | | 31,137 |
| Natural Gas Liquids (MBbls) | | 9,604 | | 7,530 | | 5,847 |
| Proved Developed Producing Reserves (MBoe) | | 49,122 | | 40,968 | | 30,186 |
| | | | | | |
| Proved Developed Non-Producing Reserves: | | | | | | |
| Oil (MBbls) | | — | | 350 | | — |
| Natural Gas (MMcf) | | — | | 461 | | — |
| Natural Gas Liquids (MBbls) | | — | | 120 | | — |
| Proved Developed Non-Producing Reserves (MBoe) | | — | | 548 | | — |
| | | | | | |
| Proved Undeveloped Reserves: | | | | | | |
| Oil (MBbls) | | 19,250 | | 20,093 | | 18,009 |
| Natural Gas (MMcf) | | 26,704 | | 29,846 | | 22,546 |
| Natural Gas Liquids (MBbls) | | 4,850 | | 5,579 | | 4,834 |
| Proved Undeveloped Reserves (MBoe) | | 28,551 | | 30,647 | | 26,601 |
| | | | | | |
| Total Proved Reserves: | | | | | | |
| Oil (MBbls) | | 48,882 | | 46,263 | | 37,158 |
| Natural Gas (MMcf) | | 86,018 | | 76,019 | | 53,683 |
| Natural Gas Liquids (MBbls) | | 14,454 | | 13,229 | | 10,681 |
| Total Proved Reserves (MBoe) | | 77,673 | | 72,163 | | 56,787 |
_____________________(1)Total proved reserves were comprised of 63%, 57%, and 53%, respectively, of total proved developed producing reserves as of December 31, 2022, September 30, 2021, and September 30, 2020.
Estimates of reserves were prepared using an average price equal to the unweighted arithmetic average of hydrocarbon prices received on a field-by-field basis on the first day of each month within the 12-month periods ended December 31, 2022, September 30, 2021, and September 30, 2020 in accordance with SEC guidelines. Reserve estimates do not include any value for probable or possible reserves that may exist, nor do they include any value for undeveloped acreage. The reserve estimates represent our net revenue interest in our properties, all of which are located within the continental United States. See "Item 1A. Risk Factors" for a discussion of risks and uncertainties associated with our estimates of proved reserves and related factors, and see Note 16 - Supplemental Information on Oil and Natural Gas Operations to the Company's consolidated financial statements included herein for further discussion of our reserve estimates and pricing.
Proved Undeveloped Reserves (PUDs)
The following table summarizes changes in the Company's estimated PUDs for the year ended December 31, 2022 (in MBoe):
| | | | | | | | |
Proved undeveloped reserves at December 31, 2021 | | 30,366 | |
| Conversions | | (1,441) | |
| Extensions and discoveries | | 7,037 | |
| Revisions | | (7,411) | |
Proved undeveloped reserves at December 31, 2022 | | 28,551 | |
During the year ended December 31, 2022, we incurred costs of approximately $20.8 million to convert 1,441 MBoe of proved undeveloped reserves to proved developed reserves. Our extensions and discoveries comprised of 7,037 MBoe were primarily due to the result of drilling activity during the year, which allowed for offset PUDs. Additionally, our downward revisions of 7,411 MBoe were primarily attributable to increases in operating costs and capital expenditures, as well as decreases in well-level projections in certain undeveloped areas.
PUDs will be converted from undeveloped to developed with successful development and as the applicable wells begin production. As of December 31, 2022, all of the Company's proved undeveloped reserves are planned to be developed within five years from the date they were initially recorded. Estimated costs relating to the future development of the Company's proved undeveloped reserves at December 31, 2022 are approximately $324.4 million, which we expect to finance through cash flow from operations, borrowings under our revolving credit facility and other sources of capital.
Evaluation and Review of Reserves
Our historical reserve estimates as of December 31, 2022 were prepared based on a report by NSAI, our independent petroleum engineers, which we refer to as the NSAI Report. The technical person primarily responsible for overseeing the preparation of the estimates is our SVP Operations and Engineering. Our SVP Operations and Engineering has been with the Company since 2016 and is the head of the reservoir engineering department. He holds a bachelor's degree in Petroleum Engineering and a Master of Business Administration with an emphasis in Energy from the University of Oklahoma. He is a member of the Society of Petroleum Engineers with over 15 years of experience in the oil and natural gas industry. Within NSAI, the technical person primarily responsible for preparing the estimates set forth in the NSAI Report is Mr. Michael B. Begland, a Licensed Professional Engineer in the State of Texas (No. 104898). Mr. Begland has been a practicing petroleum engineering consultant at NSAI since 1993 and has over 8 years of prior industry experience. He graduated from Ohio State University in 1983 with a Bachelor of Science Degree in Chemical Engineering. The technical principal meets or exceeds the education, training, and experience requirements set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers; he is proficient in judiciously applying industry standard practices to engineering and geoscience evaluations as well as applying SEC and other industry reserves definitions and guidelines. NSAI does not own an interest in any of the Company's properties, nor is it employed by us on a contingent basis.
Internal Controls
We maintain an internal staff of petroleum engineers and geoscience professionals who worked closely with our independent reserve engineers to ensure the integrity, accuracy and timeliness of the data used to calculate the Company's reserves. Our internal technical team members meet with our independent reserve engineers periodically during the period covered by the NSAI Report to discuss the assumptions and methods used in the proved reserve estimation process. The qualifications of the technical persons primarily responsible for overseeing the preparation of the estimates of our reserves are set forth in “— Evaluation and Review of Reserves” above. We provided historical information to the independent reserve engineers for the Company's properties, such as ownership interest, oil and natural gas production, well test data, commodity prices, and operating and development costs.
The preparation of the Company's reserve estimates are completed in accordance with our internal control procedures. These procedures, which are intended to ensure reliability of reserve estimations, include the following:
•review and verification of historical production data, which data is based on actual production as reported by the Company;
•communicating, collaborating, and analyzing with technical personnel in the Company's Operating and Business departments;
•preparation of reserve estimates by the Company's SVP Operations and Engineering or under his direct supervision;
•comparing and reconciling the internally generated reserves estimates to those prepared by third parties;
•confirming completeness of reserve estimates for all properties owned and verification of the use of the proper working and net revenue interests; and
•no employee's compensation is tied to the amount of reserves booked.
Estimation of Proved Reserves
Under SEC rules, proved reserves are those quantities of oil and natural gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs and under existing economic conditions, operating methods and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. If deterministic methods are used, the SEC has defined reasonable certainty for proved reserves as a “high degree of confidence that the quantities will be recovered.” All of our proved reserves as of December 31, 2022 were estimated using a deterministic method. The estimation of reserves involves two distinct determinations. The first determination results in the estimation of the quantities of recoverable oil and natural gas and the second determination results in the estimation of the uncertainty associated with those estimated quantities in accordance with the definitions established under SEC rules. The process of estimating the quantities of recoverable oil and natural gas reserves relies on the use of certain generally accepted analytical procedures. These analytical procedures fall into four broad categories or methods: (1) production performance-based methods; (2) material balance-based methods; (3) volumetric-based methods; and (4) analogy. These methods may be used singularly or in combination by the reserve evaluator in the process of estimating the quantities of reserves. Reserves for proved developed producing wells were estimated using production performance methods for the vast majority of properties. Certain new producing properties with very little production history were forecast using a combination of production performance and analogy to similar production, both of which are considered to provide a relatively high degree of accuracy. Non-producing reserve estimates, for developed and undeveloped properties, were forecast using either volumetric or analogy methods, or a combination of both. These methods provide a relatively high degree of accuracy for predicting proved developed non-producing and proved undeveloped reserves for our properties, due to the mature nature of the properties targeted for development and an abundance of subsurface control data.
To estimate economically recoverable proved reserves and related future net cash flows, NSAI considered many factors and assumptions, including the use of reservoir parameters derived from geological and engineering data which cannot be measured directly, economic criteria based on current costs and the SEC pricing requirements and forecasts of future production rates.
Under SEC rules, reasonable certainty can be established using techniques that have been proven effective by actual production from projects in the same reservoir or an analogous reservoir or by other evidence using reliable technology that establishes reasonable certainty. Reliable technology is a grouping of one or more technologies (including computational methods) that has been field tested and has been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation. To establish reasonable certainty with respect to our estimated proved reserves, the technologies and economic data used in the estimation of our proved reserves have been demonstrated to yield results with consistency and repeatability, and include production and well test data, downhole completion information, geologic data, electrical logs, radioactivity logs, core analyses, historical well cost and operating expense data.
Drilling, Acreage, and Development Activities
Drilling Results
The following table sets forth information with respect to the number of total gross and net oil wells drilled by us during the periods indicated. We do not have any natural gas wells, therefore the information set forth in the table below only pertains to oil wells. The information should not be considered indicative of future performance, nor should it be assumed that there is necessarily any correlation between the number of productive wells drilled, quantities of reserves found or economic value. Productive wells are those that produce commercial quantities of hydrocarbons, whether or not they produce a reasonable rate
of return. The following table presents our development and exploratory drilling results for the years ended December 31, 2022, September 30, 2021, and September 30, 2020 :
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Year Ended December 31, | | Year Ended September 30, |
| | 2022 | | 2021 | | 2020 |
| | Gross | | Net(1) | | Gross | | Net(1) | | Gross | | Net(1) |
| Development Wells: | | | | | | | | | | | | |
| Productive | | 17 | | 14 | | 18 | | 13 | | 11 | | 3 |
Dry(2) | | — | | — | | — | | — | | — | | — |
| Exploratory Wells: | | | | | | | | | | | | |
| Productive | | — | | — | | 2 | | 1 | | — | | — |
Dry(2) | | — | | — | | — | | — | | — | | — |
| Total Wells: | | | | | | | | | | | | |
| Productive | | 17 | | 14 | | 20 | | 14 | | 11 | | 3 |
Dry(2) | | — | | — | | — | | — | | — | | — |
_____________________(1)Net wells are gross wells multiplied by our fractional working interest.
(2)Does not include a wellbore temporarily abandoned due to mechanical failure.
We operated 93% of our horizontal production for the year ended December 31, 2022. As operator, we design and manage the development of our wells and supervise operation and maintenance activities on a day-to-day basis. Independent contractors engaged by us provide all of the equipment and personnel associated with these activities. We employ petroleum engineers, geologists and land professionals who work to improve production rates, increase reserves and lower the cost of operating our oil and natural gas properties.
Acreage Statistics
The following table sets forth our gross and net acres of developed and undeveloped leasehold as of December 31, 2022:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Developed Acreage(1) | | Undeveloped Acreage(2) | | Total Acreage |
Gross(3) | | Net(4) | | Gross(3) | | Net(4) | | Gross(3) | | Net(4) |
| 37,984 | | 27,107 | | 6,024 | | 3,363 | | 44,008 | | 30,470 |
_____________________(1)Developed acreage is acres spaced or assigned to productive wells.
(2)Undeveloped acreage are acres on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and natural gas, regardless of whether such acreage contains proved reserves.
(3)The number of gross acres is the total number of acres in which a working interest is owned.
(4)A net acre is deemed to exist when the sum of the fractional ownership working interest in gross acres equals one. The number of net acres is the sum of the fractional working interests owned in gross acres expressed as whole and fractions thereof.
Approximately 89% of our total net acreage is held by production and 4% is held by obligations. For acreage that is not held by production, unless production is established within the spacing units covering the remaining acreage or the lease is renewed or extended under continuous drilling provisions prior to the primary term expiration dates, the leases will expire in accordance with their respective terms. Substantially all of the leases governing our acreage have continuous development clauses that permit us to continue to hold the acreage under such leases after the expiration of the primary term if we initiate additional development within 120 to 180 days after the completion of the last well drilled on such lease, without the requirement of a lease extension payment. Thereafter, the lease is held with additional development every 120 to 240 days, and generally 180 days, until the entire lease is held by production. None of the Company's horizontal drilling locations associated with proved undeveloped reserves are scheduled for drilling outside of a lease term that is not accounted for with a continuous development schedule or primary term.
The following table sets forth the net undeveloped acreage, as of December 31, 2022 that will expire over the next three years unless production is established within the spacing units covering the acreage or the lease is renewed or extended under continuous drilling provisions prior to the primary term expiration dates.
| | | | | | | | | | | | | | |
| Net Undeveloped Acreage |
| 2023 | | 2024 | | 2025 |
| 1,847 | | 556 | | 764 |
Based on our current development plans, we expect to maintain substantially all of the core acreage that would otherwise expire during 2023 either through drilling and establishing production, making lease extension payments, or lease renewal efforts. Approximately 79% of our net undeveloped acreage for 2023 is currently held by continuous drilling and established production. We intend to extend or renew any core lease we plan to develop or are still assessing for development that is set to expire in 2023 and expect to incur $0.6 million to extend or renew those leases, after taking into account the drilling of wells and holding leases by production. Given our currently planned drilling activities, we do not expect the amount of any such lease extension payments to be material. Additionally, our Champions Assets acreage is 100% fee leasehold and New Mexico acreage is approximately 68% fee and state leasehold with the remaining 32% of New Mexico consisting of BLM leasehold.
Development Opportunities
The Company has a long history in the Permian Basin. In evaluating and determining drilling locations, we also consider the availability of local infrastructure, drilling support assets, property restrictions and state and local regulations. The drilling locations that we actually drill will depend on the availability of capital, regulatory approvals, commodity prices, costs, actual drilling results and other factors, and may differ from the locations currently identified.
The Company began initial planning, permitting and drilling operations during 2021 on its EOR Project, which seeks to lower decline rates and ultimately increase recovery of oil by injecting a combination of water and CO2 through vertical wells, applied to horizontal producing wells in Yoakum County, Texas. In October 2021, the Company entered into an agreement for both supply of CO2 product and for the CO2 pipeline connection. In 2022, the Company drilled and completed six injector wells and began CO2 injection after completing the water injection phase. We maintain the optionality to potentially switch to using anthropogenic CO2 with this or subsequent project areas as sources become available at attractive economics.
The Company continues to investigate numerous anthropogenic source possibilities in conjunction with CCUS efforts, including ongoing discussions with several counterparties. At the same time, we are monitoring potential changes to regulations currently being discussed at the national and Texas state levels. We continue to believe that a possible CCUS project, with Riley Permian participating as a developer, has the potential to be an attractive opportunity by itself, as well as a synergistic opportunity with our core upstream business.
Oil, Natural Gas and NGL Production, Production Prices and Production Costs
Production and Operating Data
The following table sets forth information regarding the Company's production, realized prices and production costs for the years ended December 31, 2022, September 30, 2021, and September 30, 2020.
| | | | | | | | | | | | | | | | | | | | |
| | Year Ended December 31, | | Year Ended September 30, |
| | 2022 | | 2021 | | 2020 |
| Production Data: | | | | | | |
| Oil (MBbls) | | 3,217 | | 2,340 | | 2,060 |
| Natural gas (MMcf) | | 3,229 | | 2,602 | | 1,628 |
| Natural gas liquids (MBbls) | | 444 | | 380 | | 260 |
| Total (MBoe) | | 4,199 | | 3,154 | | 2,592 |
| | | | | | |
| Daily combined volumes (Boe/d) | | 11,505 | | 8,640 | | 7,081 |
| Daily oil volumes (Bbls/d) | | 8,814 | | 6,411 | | 5,630 |
| | | | | | |
| Average Prices: | | | | | | |
| Oil ($ per Bbl) | | $ | 92.86 | | | $ | 58.29 | | | $ | 36.35 | |
Natural gas ($ per Mcf)(1) | | 3.33 | | | 2.88 | | | (0.78) | |
Natural gas liquids ($ per Bbl)(1) | | 22.22 | | | 12.41 | | | (1.90) | |
| Combined ($ per Boe) | | $ | 76.05 | | | $ | 47.12 | | | $ | 28.22 | |
| | | | | | |
| Average Prices, including derivative settlements: | | | | | | |
| Oil ($ per Bbl) | | $ | 71.75 | | | $ | 51.47 | | | $ | 49.41 | |
Natural gas ($ per Mcf)(1) | | 1.06 | | | 2.75 | | | (0.78) | |
Natural gas liquids ($ per Bbl)(1) | | 22.22 | | | 12.41 | | | (1.90) | |
| Combined ($ per Boe) | | $ | 58.13 | | | $ | 41.95 | | | $ | 38.61 | |
| | | | | | |
| Average Operating Costs per Boe: | | | | | | |
| Lease operating expenses | | $ | 7.73 | | | $ | 6.97 | | | $ | 7.81 | |
| Production and ad valorem taxes | | $ | 4.59 | | | $ | 2.74 | | | $ | 1.65 | |
_____________________(1)The Company's natural gas and NGL sales are presented net of gathering, processing and transportation fees which can result in negative average prices.
As a result of our drilling and completion activity, we increased our average net production from 8,640 Boe/d for the year ended September 30, 2021 to an average net production of 11,505 Boe/d for the year ended December 31, 2022. During the year ended December 31, 2022, our production was approximately 77% oil, 13% natural gas and 10% NGLs.
The U.S. and global markets have been disrupted and adversely affected by the COVID-19 pandemic since March 2020 and the full-scale military invasion of Ukraine by Russian troops since February 2022, which has created significant volatility in the financial markets. Commodity prices began to increase in 2021 and have continued to remain high during 2022 due to OPEC+ and other oil and natural gas producers not rapidly increasing production levels, as well as the recovery in demand related to the COVID-19 pandemic, but volatility still remains in commodity prices. Economic sanctions imposed on Russia have further exacerbated supply shortages, leading to further disruptions in the credit and capital markets, including significant uncertainty in commodity prices, during 2022.
In addition, global markets are experiencing significant inflation attributable to a number of factors. Costs for oilfield equipment and services have been affected by general inflation and we expect those costs for 2023 to continue to be a function of supply and demand.
The Company cannot estimate the length or gravity of the future impact these events will have on the Company's results of operations, financial position, and liquidity.
Productive Wells
As of December 31, 2022, we produced from 170 gross (100 net) total wells, which includes both operated and non-operated wells.
| | | | | | | | | | | | | | |
| Producing Wells | | Gross Wells | | Average Working Interest |
| Operated | | 96 | | | 95 | % |
| Non-Operated | | 74 | | | 12 | % |
| | | | |
Productive wells consist of producing wells and wells capable of production, including oil wells awaiting connection to production facilities. Gross wells are the total number of producing wells in which the Company has an interest, operated and non-operated, and net wells are the sum of our fractional working interests owned in gross wells.
Title to Properties
As is customary in the oil and natural gas industry, we initially conduct only a cursory review of the title to our properties in connection with acquisition of leasehold acreage. At such time as we determine to conduct drilling operations on those properties, we conduct a thorough title examination and perform curative work with respect to significant defects prior to commencement of drilling operations. To the extent title opinions or other investigations reflect title defects on those properties, we are typically responsible for curing any title defects at our expense. We generally will not commence drilling operations on a property until we have cured any material title defects on such property. We have obtained title opinions on substantially all of our producing properties and believe that we have satisfactory title to our producing properties in accordance with standards generally accepted in the oil and natural gas industry.
Although title to these properties is subject to encumbrances in some cases, such as customary interests generally retained in connection with the acquisition of real property, customary royalty interests and contract terms and restrictions, liens under operating agreements, liens related to environmental liabilities associated with historical operations, liens for current taxes and other burdens, easements, restrictions and minor encumbrances customary in the oil and natural gas industry, we believe that none of these liens, restrictions, easements, burdens and encumbrances will materially detract from the value of these properties or from our interest in these properties or materially interfere with our use of these properties in the operation of our business. In addition, we believe that we have obtained sufficient right-of-way grants and permits from public authorities and private parties for us to operate our business in all material respects as described in this report.
Oil and Natural Gas Leases
The typical oil and natural gas lease agreement covering our properties provides for the payment of royalties to the mineral owner for all oil and natural gas produced from any wells drilled on the leased premises. The lessor royalties and other leasehold burdens on our properties generally range from 20% to 25%, resulting in a net revenue interest generally ranging from 75% to 80%.
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 at market prices and to a relatively small number of purchasers, as is customary in the exploration, development and production business. Our purchaser contracts include marketing provisions with our purchasers to market our production. For the years ended December 31, 2022, September 30, 2021, and September 30, 2020, one purchaser accounted for 89%, 87%, and 86%, respectively, of our revenue purchased, with two end customers each accounting for more than 10% of
our revenues. During such periods, no other purchaser accounted for 10% or more of our revenues. The loss of this purchaser could materially and adversely affect our revenues in the short-term. However, the end customers include companies with lower credit risk. Further, based on the current demand for oil and natural gas and the availability of other purchasers, we believe that the loss of any of our purchasers would not have a long-term material adverse effect on our financial condition and results of operations because oil and natural gas are fungible products with well-established markets.
Transportation
We consider all gathering and delivery infrastructure in conjunction or ahead of development of an area. We strive to install such infrastructure ahead of first production to mitigate flaring and reduce operating costs. Our oil is collected from the wellhead to our tank batteries and then transported by the purchaser by truck or pipeline to a tank farm, another pipeline or a refinery. A portion of our natural gas is transported from the wellhead to the purchaser’s meter and pipeline interconnection point. In addition, we move substantially all of our produced water by pipeline connected to company-owned SWDs rather than by truck. Given the amount of disposal water volume, the connection to SWDs helps us reduce our lease operating expenses.
We are currently a party to a crude oil pipeline transportation agreement with Stakeholder Midstream Crude Oil Pipeline, LLC ("Stakeholder Midstream"). We believe we benefit from relatively low take-away costs as compared to transportation by truck, which also has the benefits of reducing truck traffic and related emissions. In August 2022, the Company amended its gas gathering and processing agreement with Stakeholder Midstream. Stakeholder Midstream committed to expand their gathering and processing system with a commitment from the Company to deliver an annual minimum volume to Stakeholder Midstream's gathering system for a minimum of seven years beginning on the in-service date of the expanded plant. While the minimum volume commitment is below our forecasted production, there are financial penalties if the minimum activity levels are not met. The additional capacity from the gas processing plant expansion is expected to lead to increased natural gas sales and decreased gas flaring for the Company.
Competition
We operate in a highly competitive environment for acquiring properties, marketing oil and natural gas and securing trained personnel. Some of our competitors possess and employ financial resources substantially greater than ours and some competitors employ more technical personnel. These factors can be particularly important in the areas in which we operate. Those companies may be able to pay more for productive oil and natural gas properties and exploratory prospects, and to evaluate, bid for, and purchase a greater number of properties and prospects than what our financial or technical resources permit. Our ability to acquire additional properties and to find and develop reserves in the future will depend on our ability to identify, evaluate and select suitable properties and to consummate transactions in a highly competitive environment.
Seasonality of Business
Weather conditions affect the demand for, and prices of, oil, natural gas and NGLs. Demand for oil, natural gas and NGLs is typically higher in the fourth and first calendar quarters resulting in higher prices. Due to these seasonal fluctuations, results of operations for individual quarterly periods may not be indicative of the results that may be realized on an annual basis.
Regulation of the Oil and Natural Gas Industry
REPX’s operations are substantially affected by federal, state and local laws and regulations. In particular, natural gas production and related operations are, or have been, subject to price controls, taxes and numerous other laws and regulations. All of the jurisdictions in which REPX owns or operates producing oil and natural gas properties have statutory provisions regulating the development and production of oil and natural gas, including 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. REPX’s operations are also subject to various conservation laws and regulations. These include the regulation of the size of drilling and spacing units or proration units, the number of wells which may be drilled in an area and the unitization or pooling of crude oil or natural gas wells, as well as regulations that generally prohibit the venting or flaring of natural gas and impose certain requirements regarding the ratability or fair apportionment of production from fields and individual wells. State laws including in Texas govern a number of conservation matters, including provisions for the unitization or pooling of oil and natural gas properties, the establishment of maximum allowable rates of production from oil and natural gas wells, the regulation of well spacing or density, and plugging and abandonment of wells. The effect of these regulations is to limit the amount of oil and natural gas that REPX can produce from its wells and to limit the number of wells or the locations at which REPX can drill, although REPX can apply for exceptions to
such regulations or to have reductions in well spacing or density. Moreover, Texas imposes a production or severance tax with respect to the production and sale of oil, natural gas and NGLs within its jurisdiction.
Failure to comply with applicable laws and regulations can result in substantial penalties. The regulatory burden on the industry increases the cost of doing business and affects profitability. Although REPX believes it is in substantial compliance with all applicable laws and regulations, such laws and regulations are frequently amended or reinterpreted. Therefore, REPX is unable to predict the future costs or impact of compliance. Additional proposals and proceedings that affect the oil and natural gas industry are regularly considered by Congress, the states, FERC and the courts. REPX cannot predict when or whether any such proposals may become effective. REPX does not believe that it would be affected by any such action materially different than similarly situated competitors.
Regulation Affecting Production
The production of oil and natural gas is subject to United States federal and state laws and regulations, and orders of regulatory bodies under those laws and regulations, governing a wide variety of matters. All of the jurisdictions in which REPX owns or operates producing oil and natural gas properties have statutory provisions regulating the exploration for and production of oil and natural gas, including 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. REPX’s operations are also subject to various conservation laws and regulations. These include the regulation of the size of drilling and spacing units or proration units, the number of wells which may be drilled in an area, and the unitization or pooling of oil or natural gas wells, as well as regulations that generally prohibit the venting or flaring of natural gas, and impose certain requirements regarding the ratability or fair apportionment of production from fields and individual wells. These laws and regulations may limit the amount of oil and natural gas wells REPX can drill. Moreover, each state generally imposes a production or severance tax with respect to the production and sale of oil, natural gas and NGLs within its jurisdiction. States do not regulate wellhead prices or engage in other similar direct regulation, but there can be no assurance that they will not do so in the future. The effect of such future regulations may be to limit the amounts of oil and natural gas that may be produced from REPX’s wells, negatively affect the economics of production from these wells or limit the number of locations REPX can drill.
The failure to comply with the rules and regulations of oil and natural gas production and related operations can result in substantial penalties. REPX’s competitors in the oil and natural gas industry are subject to the same regulatory requirements and restrictions that affect REPX’s operations.
Regulation of Sales and Transportation of Oil
Sales of oil, condensate and NGLs are not currently regulated and are made at negotiated prices. Although prices of these energy commodities are currently unregulated, the United States Congress historically has been active in their regulation. REPX cannot predict whether new legislation to regulate oil and NGLs, or the prices charged for these commodities might be proposed, what proposals, if any, might actually be enacted by the United States Congress or the various state legislatures and what effect, if any, the proposals might have on REPX’s operations. Additionally, such sales may be subject to certain state, and potentially federal, reporting requirements.
REPX’s sales of oil are affected by the availability, terms and cost of transportation. Prices received from the sale of crude oil and NGLs may be affected by the cost of transporting those products to market. FERC has jurisdiction under the Interstate Commerce Act (“ICA”), as it existed in 1977, over common carriers engaged in the transportation in interstate commerce by pipeline of crude oil, NGLs and refined petroleum products as part of the continuous movement of the crude oil, NGLs or refined petroleum products in interstate commerce. The ICA requires that pipelines providing jurisdictional movements maintain a tariff on file with FERC. The tariff sets forth the established rates as well as the rules and regulations governing the service. The ICA requires, among other things, that rates and terms and conditions of service be “just and reasonable.” In general, interstate oil pipeline rates must be cost-based, although indexed rates, settlement rates agreed to by all shippers are permitted and market based rates may be permitted in certain circumstances. Such pipelines must also provide jurisdictional service in a manner that is not unduly discriminatory or unduly preferential. Shippers have the power to challenge new and existing rates and terms and conditions of service before FERC.
Intrastate oil pipeline transportation rates are subject to regulation by state regulatory commissions. The basis for intrastate oil pipeline regulation, and the degree of regulatory oversight and scrutiny given to intrastate oil pipeline rates, varies from state to state. Insofar as effective interstate and intrastate rates and regulations regarding access are equally applicable to all
comparable shippers, REPX believes that the regulation of oil transportation will not affect REPX’s operations in any way that is of material difference from those of REPX’s competitors who are similarly situated.
Regulation of Transportation and Sales of Natural Gas
Historically, the transportation and sale for resale of natural gas in interstate commerce have been regulated by agencies of the U.S. federal government, primarily FERC. In the past, the federal government has regulated the prices at which natural gas could be sold. While sales by producers of natural gas can currently be made at uncontrolled market prices, Congress could reenact price controls in the future. Deregulation of wellhead natural gas sales began with the enactment of the NGPA, and culminated in adoption of the Natural Gas Wellhead Decontrol Act which removed controls affecting wellhead sales of natural gas effective January 1, 1993. The transportation and sale for resale of natural gas in interstate commerce is regulated primarily under the NGA, and by regulations and orders promulgated under the NGA by FERC. In certain limited circumstances, intrastate transportation and wholesale sales of natural gas may also be affected directly or indirectly by laws enacted by Congress and by FERC regulations.
The Energy Policy ("EP") Act of 2005 is a comprehensive compilation of tax incentives, authorized appropriations for grants and guaranteed loans and significant changes to the statutory policy that affects all segments of the energy industry. Among other matters, the EP Act of 2005 amends the NGA to add an anti-market manipulation provision which makes it unlawful for any entity to engage in prohibited behavior to be prescribed by FERC, and furthermore provides FERC with additional civil penalty authority. The EP Act of 2005 provides FERC with the power to assess civil penalties of up to $1,000,000 per day for violations of the NGA and increases FERC’s civil penalty authority under the NGPA from $5,000 per violation per day to $1,000,000 per violation per day. The civil penalty provisions are applicable to entities that engage in the sale of natural gas for resale in interstate commerce. On January 19, 2006, FERC issued Order No. 670, a rule implementing the anti-market manipulation provision of the EP Act of 2005, and subsequently denied rehearing. The rules make it unlawful to: (i) in connection with the purchase or sale of natural gas subject to the jurisdiction of FERC, or the purchase or sale of transportation services subject to the jurisdiction of FERC, for any entity, directly or indirectly, to use or employ any device, scheme or artifice to defraud; (ii) to make any untrue statement of material fact or omit to make any such statement necessary to make the statements made not misleading; or (iii) to engage in any act or practice that operates as a fraud or deceit upon any person. The new anti-market manipulation rule does not apply to activities that relate only to intrastate or other non-jurisdictional sales or gathering, but does apply to activities of natural gas pipelines and storage companies that provide interstate services, as well as otherwise non-jurisdictional entities to the extent the activities are conducted “in connection with” natural gas sales, purchases or transportation subject to FERC jurisdiction, which now includes the annual reporting requirements under Order 704, described below. The anti-market manipulation rule and enhanced civil penalty authority reflect an expansion of FERC’s NGA enforcement authority.
On December 26, 2007, FERC issued Order 704, a final rule on the annual natural gas transaction reporting requirements, as amended by subsequent orders on rehearing. Under Order 704, any market participant that engages in wholesale sales or purchases of natural gas that equal or exceed 2,200,000 MMBtus of physical natural gas in the previous calendar year, including natural gas producers, gatherers and marketers, are required to report, on May 1 of each year, aggregate volumes of natural gas purchased or sold at wholesale in the prior calendar year to the extent such transactions utilize, contribute to, or may contribute to the formation of price indices to FERC on Form No. 552. It is the responsibility of the reporting entity to determine which individual transactions should be reported based on the guidance of Order 704. Order 704 also requires market participants to indicate whether they report prices to any index publishers, and if so, whether their reporting complies with FERC’s policy statement on price reporting.
Gathering service, which occurs upstream of jurisdictional transmission services, is regulated by the states onshore and in state waters. Section 1(b) of the NGA exempts natural gas gathering facilities from regulation by FERC as a natural gas company under the NGA. Although FERC has set forth a general test for determining whether facilities perform a non-jurisdictional gathering function or a jurisdictional transmission function, FERC’s determinations as to the classification of facilities are done on a case by case basis. To the extent that FERC issues an order that reclassifies certain jurisdictional transmission facilities as non-jurisdictional gathering facilities, and depending on the scope of that decision, REPX’s costs of getting natural gas to point of sale locations may increase. REPX believes that the natural gas pipelines in the gathering systems REPX uses meet the traditional tests FERC has used to establish a pipeline’s status as a gatherer not subject to regulation as a natural gas company. However, the distinction between FERC-regulated transmission services and federally unregulated gathering services is the subject of ongoing litigation, so the classification and regulation of the gathering facilities REPX owns and uses are subject to change based on future determinations by FERC, the courts or Congress. State regulation of natural gas gathering facilities generally includes various occupational safety, environmental and, in some circumstances, nondiscriminatory-take requirements. Natural gas gathering may receive greater regulatory scrutiny at the state level. State
regulation of gathering facilities generally includes various safety, environmental and, in some circumstances, nondiscriminatory take requirements and complaint-based rate regulation. Gathering operations could also be subject to safety and operational regulations relating to the design, construction, testing, operation, replacement and maintenance of gathering facilities.
The price at which REPX sells natural gas is not currently subject to federal rate regulation and, for the most part, is not subject to state regulation. However, with regard to REPX’s physical sales of these energy commodities, REPX is required to observe anti-market manipulation laws and related regulations enforced by FERC under the EP Act of 2005 and under the Commodity Exchange Act (“CEA”), and regulations promulgated thereunder by the Commodity Futures Trading Commission ("CFTC"). The CEA prohibits any person from manipulating or attempting to manipulate the price of any commodity in interstate commerce or futures on such commodity. The CEA also prohibits knowingly delivering or causing to be delivered false or misleading or knowingly inaccurate reports concerning market information or conditions that affect or tend to affect the price of a commodity. Should REPX violate the anti-market manipulation laws and regulations, REPX could also be subject to related third-party damage claims by, among others, sellers, royalty owners and taxing authorities.
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, REPX believes that the regulation of similarly situated intrastate natural gas transportation in any states in which REPX operates and ships natural gas on an intrastate basis will not affect REPX’s operations in any way that is of material difference from those of REPX’s competitors. Like the regulation of interstate transportation rates, the regulation of intrastate transportation rates affects the marketing of natural gas that REPX produces, as well as the revenues REPX receives for sales of its natural gas.
Changes in law and to FERC or state policies and regulations may adversely affect the availability and reliability of firm and/or interruptible transportation service on interstate and intrastate pipelines, and REPX cannot predict what future action FERC or state regulatory bodies will take. REPX does not believe, however, that any regulatory changes will affect REPX in a way that materially differs from the way they will affect other natural gas producers and marketers with which REPX competes.
Regulation of Environmental and Occupational Safety and Health Matters
REPX’s oil and natural gas development operations are subject to numerous stringent federal, regional, state and local statutes and regulations governing occupational safety and health, the discharge of materials into the environment or otherwise relating to environmental and human health protection, some of which carry substantial administrative, civil and criminal penalties for failure to comply. These laws and regulations may (i) require the acquisition of a permit before drilling or other regulated activity commences; (ii) restrict the types, quantities and concentrations of various substances that can be released into the environment; (iii) govern the sourcing and disposal of water used in the drilling and completion process; (iv) limit or prohibit drilling or other operational activities in certain areas and on certain lands lying within wilderness, wetlands, frontier, threatened or endangered species habitat and other protected areas; (v) require some form of remedial action to prevent or mitigate pollution from former operations such as plugging abandoned wells or closing earthen pits; (vi) establish specific safety and health criteria addressing worker protection; (vii) impose substantial liabilities for pollution resulting from operations or failure to comply with regulations, including permitting requirements; (viii) require the installation of costly emission monitoring and/or pollution control equipment; (ix) require the preparation and implementation of oil spill prevention, control, and countermeasure plans and risk management plans; and (x) require the reporting of the types and quantities of various substances that are generated, stored, processed, released, or disposed of in connection with REPX’s properties. In addition, these laws and regulations may restrict the rate of production. Failure to comply with these laws and regulations may result in the assessment of substantial administrative, civil, and criminal penalties, as well as possible issuance of injunctions limiting or prohibiting REPX's activities.
The following is a summary of the more significant existing environmental and occupational health and safety laws and regulations, as amended from time to time, to which REPX’s business operations are subject and for which compliance may have a material adverse impact on REPX’s capital expenditures, results of operations or financial position.
Hazardous Substances and Waste Handling
The Comprehensive Environmental Response, Compensation, and Liability Act of 1980 (“CERCLA”), also known as the “Superfund” law, and comparable state laws impose joint and several liability, without regard to fault or the legality of the original conduct, on certain classes of persons that are considered to have contributed to the release of a “hazardous substance”
into the environment. These persons include the current and past owner or operator of the disposal site or the site where the release occurred and anyone who disposed or arranged for the transport or disposal of the hazardous substances at the site where the release occurred. Under CERCLA, such persons may be subject to joint and several strict liability for the costs of cleaning up the hazardous substances that have been released into the environment, for damages to natural resources, and for certain health studies. It is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment. REPX generates materials in the course of REPX’s operations that may be regulated as “hazardous substances”. REPX is able to control directly the operation of only those wells with respect to which REPX acts as operator. Notwithstanding REPX’s lack of direct control over wells operated by others, the failure of an operator other than REPX to comply with applicable environmental regulations or the failure of a facility receiving hazardous substances for treatment or disposal to manage the substances properly may, in certain circumstances, be attributed to REPX and result in CERCLA or comparable liability.
The Resource Conservation and Recovery Act (“RCRA”) and analogous state laws, impose detailed requirements for the generation, handling, storage, treatment and disposal of nonhazardous and hazardous solid wastes. RCRA specifically excludes drilling fluids, produced waters and other wastes associated with the development or production of crude oil, natural gas or geothermal energy from regulation as hazardous wastes. However, these wastes may be regulated by the EPA or state agencies under RCRA’s less stringent nonhazardous solid waste provisions, state laws or other federal laws. Moreover, it is possible that these particular oil and natural gas development and production wastes now classified as nonhazardous solid wastes could be classified as hazardous wastes in the future. For example, in December 2016, the EPA and environmental groups entered into a consent decree to address EPA’s alleged failure to timely assess RCRA Subtitle D criteria regulations exempting certain exploration and production related oil and natural gas wastes from regulation as hazardous wastes under RCRA. The consent decree required EPA to propose a rulemaking no later than March 15, 2019 for revision of the Subtitle D criteria regulations pertaining to oil and natural gas wastes or to sign a determination that revision of the regulations is not necessary. EPA ultimately concluded that revision of the Subtitle D criteria regulations regarding oil and natural gas wastes is not necessary at this time. But, should future rulemakings or legal challenges result in a loss of the RCRA hazardous-waste exclusion for drilling fluids, produced waters and related wastes, REPX’s costs to manage and dispose of generated wastes could increase, which could have a material adverse effect on REPX’s results of operations and financial position. In addition, in the course of REPX’s operations, REPX generates some amounts of ordinary industrial wastes, such as paint wastes, waste solvents, laboratory wastes and waste compressor oils that may be regulated as hazardous wastes if such wastes are listed as hazardous wastes or have hazardous characteristics.
REPX currently owns, leases or operates numerous properties that have been used for oil and natural gas development and production activities for many years. Although REPX believes that it has utilized operating and waste disposal practices that were standard in the industry at the time, hazardous substances, wastes or petroleum hydrocarbons may have been released on, under or from the properties owned or leased by REPX, or on, under or from other locations, including off-site locations, where such substances have been taken for recycling, treatment or disposal. In addition, some of REPX’s properties have been operated by third parties or by previous owners or operators whose treatment and disposal of hazardous substances, wastes or petroleum hydrocarbons was not under REPX’s control. These properties and the substances disposed or released on, under or from them may be subject to CERCLA, RCRA and analogous state laws. Under such laws, REPX could be required to undertake response or corrective measures, which could include investigation of the nature and extent of contamination, removal of previously disposed substances and wastes, cleanup of contaminated property or performance of remedial plugging or pit closure operations to prevent future contamination.
Water Discharges
The CWA and comparable state laws impose restrictions and strict controls regarding the discharge of pollutants, including produced waters and other oil and natural gas wastes, into or near navigable waters. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by the EPA or the state. The discharge of dredge and fill material in regulated waters, including wetlands, is also prohibited, unless authorized by a permit issued by the U.S. Army Corps of Engineers (the “Corps”). In May 2015, the EPA and the Corps issued a new rule to revise the definition of “Waters of the United States” for all Clean Water Act Programs ("WOTUS"). The 2015 rule made additional waters expressly “Waters of the United States” and, therefore, subject to the jurisdiction of the Clean Water Act, rather than subject to a case-specific evaluation. Legal challenges to this rule followed and the rule was stayed nationwide by the U.S. Sixth Circuit Court of Appeals in October 2015. In response to this decision, the EPA and the Corps resumed nationwide use of the agencies’ prior regulations defining the term “Waters of the United States.” On February 1, 2018, the EPA officially delayed implementation of the 2015 rule until early 2020. The EPA and the Corps also issued a supplemental rulemaking in July 2018 requesting additional comment on the proposed repeal of the 2015 rule’s definition of “Waters of the United States.” However, as the result of an order by the U.S. District Court for the District of South Carolina on August 16, 2018, and subsequent state filings,
the 2015 rule was in effect in 23 states, including in Texas. On February 14, 2019, the EPA and the Corps issued a proposed rule to revise the definition of “Waters of the United States.” The proposed rule, known as the Navigable Waters Protection Rule, narrowed the definition, excluding, for example, streams that do not flow year-round and wetlands without a direct surface connection to other jurisdictional waters. In September 2019, EPA finalized the repeal of the 2015 WOTUS rule, and the repeal became effective in December 2019. On June 22, 2020, the Navigable Waters Protection Rule became effective. However, on August 30, 2021, the U.S. District Court for the District of Arizona issued an order vacating and remanding the Navigable Waters Protection Rule. In response, the EPA and the Corps issued a joint statement indicating that the agencies are halting implementation of the Navigable Waters Protection Rule, and are reverting back to the pre-2015 definition of "waters of the United States." On November 18, 2021, the EPA and the Department of the Army released a pre-publication version of their proposed rule to reinstate the pre-2015 definition of "waters of the United States," updated to reflect consideration of Supreme Court Decisions. This proposed rule was published in the Federal Register on December 7, 2021. Due to the administrative procedures required to establish the rule and potential litigation, the new definition of “Waters of the United States” may not be implemented, if at all, for several years. To the extent any litigation or future amendments to the rule expand the scope of the Clean Water Act’s jurisdiction, REPX could face increased costs and delays with respect to obtaining permits for dredge and fill activities in wetland areas or in connection with stream crossings and preparation and implementation of oil spill prevention, control, and countermeasure plans. Obtaining permits has the potential to delay the development of oil and natural gas projects. These laws and any implementing regulations provide for administrative, civil and criminal penalties for any unauthorized discharges of oil and other substances in reportable quantities and may impose substantial potential liability for the costs of removal, remediation and damages.
Pursuant to CWA laws and regulations, REPX may be required to obtain and maintain approvals or permits for the discharge of wastewater or storm water. Spill prevention, control and countermeasure (“SPCC”) requirements imposed under the CWA require operators of certain oil and natural gas facilities that store oil in more than threshold quantities, the release of which could reasonably be expected to reach jurisdictional waters, to develop, implement, and maintain SPCC plans. REPX has undertaken a review of REPX’s properties to determine the need for new or updated SPCC plans and, where necessary, REPX has developed or upgraded such plans and has implemented the physical and operation controls imposed by these plans.
The primary federal law related specifically to oil spill liability is the Oil Pollution Act of 1990 (“OPA”), which amends and augments the oil spill provisions of the Clean Water Act and imposes certain duties and liabilities on certain “responsible parties” related to the prevention of oil spills and damages resulting from such spills in or threatening waters of the United States or adjoining shorelines. For example, operators of certain oil and natural gas facilities must develop, implement and maintain facility response plans, conduct annual spill training for certain employees and provide varying degrees of financial assurance. Owners or operators of a facility, vessel or pipeline that is a source of an oil discharge or that poses a substantial threat of discharge is one type of “responsible party” who is liable. The OPA applies joint and several liability, without regard to fault, to each liable party for oil removal costs and a variety of public and private damages. Although defenses exist, they are limited. As such, a violation of the OPA has the potential to adversely affect REPX’s operations.
Subsurface Injections
In the course of REPX’s operations, REPX produces water in addition to oil and natural gas. Water that is not recycled may be disposed of in disposal wells, which inject the produced water into non-producing subsurface formations. Underground injection operations are regulated pursuant to the Underground Injection Control (“UIC”) program established under the U.S. Safe Drinking Water Act’s (“SDWA”) and analogous state laws. The UIC program requires permits from the EPA or state agency to which the UIC program has been delegated for the construction and operation of disposal wells, establishes minimum standards for disposal well operations, and restricts the types and quantities of fluids that may be disposed. A change in UIC disposal well regulations or the inability to obtain permits for new disposal wells in the future may affect REPX’s ability to dispose of produced water and ultimately increase the cost of REPX’s operations. For example, in response to recent seismic events below ground near disposal wells used for the injection of oil and natural gas-related wastewaters, regulators in some states, including Texas, have imposed more stringent permitting and operating requirements for produced water disposal wells. In 2014, the RRC published a final rule governing permitting or re-permitting of disposal wells that would require, among other things, the submission of information on seismic events occurring within a specified radius of the disposal well location, as well as logs, geologic cross sections and structure maps relating to the disposal area in question. If the permittee or an applicant of a disposal well permit fails to demonstrate that the injected fluids are confined to the disposal zone or if scientific data indicates such a disposal well is likely to be or determined to be contributing to seismic activity, then the RRC may deny, modify, suspend or terminate the permit application or existing operating permit for that well. Additionally, legal disputes may arise based on allegations that disposal well operations have caused damage to neighboring properties or otherwise violated state or federal rules regulating waste disposal. These developments could result in additional regulation, restriction on the use of injection wells by REPX or by commercial disposal well vendors whom REPX may use from time to time to dispose of
wastewater, and increased costs of compliance, which could have a material adverse effect on REPX’s capital expenditures and operating costs, financial condition, and results of operations.
In addition, several cases have recently put a spotlight on the issue of whether injection wells may be regulated under the CWA if a direct hydrological connection to a jurisdictional surface water can be established. The split among federal circuit courts of appeals that decided these cases engendered two petitions for writ of certiorari to the United States Supreme Court in August 2018, one of which was granted in February 2019. The EPA has also brought attention to the reach of the CWA’s jurisdiction in such instances by issuing a request for comment in February 2018 regarding the applicability of the CWA permitting program to discharges into groundwater with a direct hydrological connection to jurisdictional surface water, which hydrological connections should be considered “direct,” and whether such discharges would be better addressed through other federal or state programs. The EPA followed up its Request for Comments with an Interpretative Statement and additional Request for Comment in April 2019 stating that the agency does not believe indirect discharges from a point source through a hydrological groundwater connection to surface water are regulated under the CWA, although the agency indicated that this guidance may be amended pending the Supreme Court’s decision. In April, 2020, the Supreme Court issued a ruling in the case, County of Maui, Hawaii v. Hawaii Wildlife Fund, holding that discharges into groundwater may be regulated under the CWA if the discharge is the “functional equivalent” of a direct discharge into navigable waters. On January 14, 2021, the EPA issued a guidance on the ruling, which emphasized that discharges to groundwater are not necessarily the “functional equivalent” of a direct discharge based solely on proximity to jurisdictional waters. However, on September 16, 2021, the EPA rescinded its prior guidance. The U.S. Supreme Court’s ruling in County of Maui, Hawaii v. Hawaii Wildlife Fund could result in increased operational costs for REPX if permits are required under the CWA for disposal of REPX’s flowback and produced water in disposal wells.
Air Emissions
The Federal Clean Air Act (“CAA”) and comparable state laws restrict the emission of air pollutants from many sources, such as tank batteries and compressor stations, through air emissions standards, construction and operating permitting programs and the imposition of other compliance requirements. These laws and regulations may require REPX to obtain pre-approval for the construction or modification of certain projects or facilities expected to produce or significantly increase air emissions, obtain and strictly comply with stringent air permit requirements or utilize specific equipment or technologies to control emissions of certain pollutants. Over the next several years, REPX may be required to incur certain capital expenditures for air pollution control equipment or other air emissions related issues. For example, in October 2015, the EPA lowered the National Ambient Air Quality Standard, ("NAAQS") for ozone from 75 to 70 parts per billion. State implementation of the revised NAAQS could result in stricter permitting requirements, delay or prohibit REPX’s ability to obtain such permits and result in increased expenditures for pollution control equipment, the costs of which could be significant. In addition, beginning in 2012, the EPA adopted new rules under the CAA that require the reduction of volatile organic compound emissions from certain fractured and refractured natural gas and, in 2016, oil wells for which well completion operations are conducted (i.e. use reduced emission completions, also known as “green completions”). These regulations also establish specific new requirements regarding emissions from production-related wet seal and reciprocating compressors, pneumatic controllers, storage vessels, and well-site components (fugitive emissions). In September 2020, the EPA scaled back these rules by removing the transmission and storage sectors of the oil and natural gas industry from regulation under the New Source Performance Standards (“NSPS”) and rescinding methane-specific standards for the production and processing segments of the industry. However, in June 2021, Congress partially overturned the rollback using the Congressional Review Act, leaving the original regulations largely in place. Furthermore, in November 2021, the EPA issued a proposed rule which would update, strengthen, and expand the 2016 regulations for methane and volatile organic compound ("VOC") emissions from new, modified, and reconstructed sources, and, significantly, also includes emissions guidelines to assist states in the development of plans to regulate methane emissions from certain existing sources. In May 2016, the EPA finalized rules regarding criteria for aggregating multiple small surface sites into a single source for air-quality permitting purposes applicable to the oil and natural gas industry. This rule could cause small facilities located in areas where air permitting is implemented by the EPA, on an aggregate basis, to be deemed a major source, thereby triggering more stringent air permitting processes and requirements. See also “—Regulation of GHG Emissions.”
Compliance with these and other air pollution control and permitting requirements has the potential to delay the development of oil and natural gas projects and increase REPX’s costs of development, which costs could be significant. States may also impose more stringent air permitting and air quality requirements than federal requirements. For example, in March 2021, the New Mexico Oil Conservation Commission finalized rules to eliminate venting and flaring at new and existing wells, and requiring operators to capture at least 98% of natural gas produced from their wells by 2026. In addition, the New Mexico Environment Department adopted a rule in August 2022 that requires oil and natural gas producers in counties that are at risk of non-attainment of federal ozone standards to, among other things, check emission rates and have those calculations certified by
a qualified engineer, perform enhanced checks for leaks, and repair them within 15 days of discovery, and maintain records to demonstrate continuous compliance.
Regulation of GHG Emissions
In response to findings that emissions of carbon dioxide, methane and other GHGs present an endangerment to public health and the environment, the EPA has adopted regulations pursuant to the federal CAA that, among other things, require preconstruction and operating permits for certain large stationary sources. Facilities required to obtain preconstruction permits for their GHG emissions are also required to meet “best available control technology” standards that are being established by the states or, in some cases, by the EPA on a case-by-case basis. These regulatory requirements could adversely affect REPX’s operations and restrict or delay REPX’s 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 natural gas production sources in the United States on an annual basis, which include certain of REPX’s operations. Furthermore, in May 2016, the EPA finalized the NSPS Subpart OOOOa standards that establish new controls for emissions of methane from new, modified or reconstructed sources in the oil and natural gas source category, including production, processing, transmission and storage activities. The rules include first-time standards to address emissions of methane from equipment and processes across the source category, including hydraulically fractured oil and natural gas well completions. In addition, the rules impose leak detection and repair requirements intended to address methane and other emissions leaks known as “fugitive emissions” from equipment, such as valves, connectors, open ended lines, pressure-relief devices, compressors, instruments and meters. Although much of the initial rules remain intact and effective, the rules have been subject to legal challenges, reconsideration by the EPA, stays, and proposed amendments. For example, the EPA published two new rules on September 14 and 15, 2020 that remove the transmission and storage sectors of the oil and natural gas industry from regulation under the NSPS and rescind methane-specific standards for the production and processing segments of the industry. However, states and environmental groups brought suit challenging the new rules almost immediately, and in June 2021, Congress partially overturned the rollback. Furthermore, in November 2021 and November 2022, EPA issued proposed rules which would update, strengthen, and expand the NSPS Subpart OOOOa regulations for methane and VOC emissions from new, modified, and reconstructed sources. Notably, the proposed rules also include emissions guidelines to assist states in the development of plans to regulate methane emissions from certain existing sources. Legal challenges to the proposed rules are likely to follow, and thus, the ultimate scope of these regulations remains uncertain. Compliance with these rules requires enhanced record-keeping practices, the purchase of new equipment such as optical gas imaging instruments to detect leaks and increased frequency of maintenance and repair activities to address emissions leakage. The rules will also likely require hiring additional personnel to support these activities or the engagement of third party contractors to assist with and verify compliance. The BLM also finalized similar rules regarding the control of methane emissions in November 2016 that apply to oil and natural gas exploration and development activities on federal and Indian lands. The rules sought to minimize venting and flaring of emissions from storage tanks and other equipment, and also impose leak detection and repair requirements. However, due to subsequent BLM revisions and multiple legal challenges, the rules were never fully implemented, and in October 2020, the November 2016 rules were struck down by the District Court of Wyoming as the result of one such challenge. New Mexico and California have since filed an appeal of the Wyoming Court's decision in the Tenth Circuit. These new and proposed rules could result in increased compliance costs on REPX’s operations.
Hydraulic Fracturing Activities
Hydraulic fracturing is an important and common practice that is used to stimulate production of oil and/or natural gas from dense subsurface rock formations. The hydraulic fracturing process involves the injection of water, proppants and chemicals under pressure into targeted subsurface formations to fracture the surrounding rock and stimulate production. REPX regularly uses hydraulic fracturing as part of its operations. Hydraulic fracturing is typically regulated by state oil and natural gas commissions, but federal agencies have asserted jurisdiction over certain aspects of the process. The EPA has asserted federal regulatory authority pursuant to the SDWA over certain hydraulic fracturing activities involving the use of diesel fuels and published permitting guidance in February 2014 addressing the performance of such activities using diesel fuels. The EPA has also taken the following actions: issued final regulations under the federal CAA establishing performance standards, including standards for the capture of air emissions released during hydraulic fracturing; although final rules have not yet been issued, proposed a rulemaking under the Toxic Substances Control Act to require companies to disclose information regarding the chemicals used in hydraulic fracturing; and, in June 2016, published an effluent limitation guideline final rule prohibiting the discharge of wastewater from onshore unconventional oil and natural gas extraction facilities to publicly owned wastewater treatment plants. In addition, the BLM finalized rules in March 2015 that impose new or more stringent standards for performing hydraulic fracturing on federal and American Indian lands, including requirements for chemical disclosure, wellbore integrity, and handling of flowback water. However, following years of litigation, the BLM rescinded the rule in December 2017. BLM’s repeal of the rule was challenged in court, and in April 2020, the Northern District of California issued
a ruling in favor of the BLM. This ruling is now being appealed; thus, the future of the rule remains uncertain. In addition, Congress has from time to time considered legislation to provide for federal regulation of hydraulic fracturing under the SDWA and to require disclosure of the chemicals used in the hydraulic fracturing process. It is unclear how any additional federal regulation of hydraulic fracturing activities may affect REPX’s operations.
Certain governmental reviews have recently been conducted or are underway that focus on environmental aspects of hydraulic fracturing practices. For example, in December 2016, the EPA released its final report on the potential impacts of hydraulic fracturing on drinking water resources. The final report concluded that “water cycle” activities associated with hydraulic fracturing may impact drinking water resources “under some circumstances,” noting that the following hydraulic fracturing water cycle activities and local- or regional-scale factors are more likely than others to result in more frequent or more severe impacts: water withdrawals for fracturing in times or areas of low water availability; surface spills during the management of fracturing fluids, chemicals or produced water; injection of fracturing fluids into wells with inadequate mechanical integrity; injection of fracturing fluids directly into groundwater resources; discharge of inadequately treated fracturing wastewater to surface waters; and disposal or storage of fracturing wastewater in unlined pits. Since the report did not find a direct link between hydraulic fracturing itself and contamination of groundwater resources, this years-long study report does not appear to provide any basis for further regulation of hydraulic fracturing at the federal level. More recently, the EPA initiated a study of Oil and Gas Extraction Wastewater Management in 2018 that the agency characterizes as a “holistic look” at how produced water is regulated and managed by the EPA, states, and tribes, and has sought input on these issues from other stakeholders such as academics, non-governmental organizations, and industry. A primary focus of the study is to evaluate whether federal regulations allowing for more discharge options would be beneficial, for example, in addressing areas with concerns over scarcity of water and/or injection options. The EPA released a draft of the study in May 2019 and sought public input until July 1, 2019. The EPA’s final report was issued in May 2020, which found mixed support from stakeholders regarding additional produced water discharge options. The EPA is still determining what, if any, next steps are appropriate regarding produced water management in light of the report. These ongoing or proposed studies could spur initiatives to further regulate hydraulic fracturing under the federal SDWA, CWA or other regulatory mechanisms.
At the state level, several states have adopted or are considering legal requirements that could impose more stringent permitting, disclosure and well construction requirements on hydraulic fracturing activities. For example, in May 2013, the RRC issued a “well integrity rule,” which updates the requirements for drilling, putting pipe down and cementing wells. The rule also includes new testing and reporting requirements, such as (i) the requirement to submit cementing reports after well completion or after cessation of drilling, whichever is later, and (ii) the imposition of additional testing on wells less than 1,000 feet below usable groundwater. The well integrity rule took effect in January 2014. Local governments also may seek to adopt ordinances within their jurisdictions regulating the time, place and manner of drilling activities in general or hydraulic fracturing activities in particular.
Compliance with existing related laws has not had a material adverse effect on REPX’s operations or financial position, but if new or more stringent federal, state or local legal restrictions relating to the hydraulic fracturing process are adopted in areas where REPX operates, REPX could incur potentially significant added costs to comply with such requirements, experience delays or curtailment in the pursuit of development activities, and perhaps even be precluded from drilling wells.
Protected Species
The Endangered Species Act (“ESA”) and (in some cases) comparable state laws were established to protect endangered and threatened species. Pursuant to the ESA, if a species is listed as threatened or endangered, restrictions may be imposed on activities adversely affecting that species or that species’ habitat. REPX may conduct operations on oil and natural gas leases in areas where certain species that are listed as threatened or endangered are known to exist and where other species that potentially could be listed as threatened or endangered under the ESA may exist. The U.S. Fish and Wildlife Service may designate critical habitat and suitable habitat areas that it believes are necessary for survival of a threatened or endangered species. A critical habitat or suitable habitat designation could result in further material restrictions to land use and may materially delay or prohibit land access for oil and natural gas development. Similar protections are offered to migratory birds under the Migratory Bird Treaty Act and the Bald and Golden Eagle Protection Act. In the past, the federal government has issued indictments under the Migratory Bird Treaty Act to several oil and natural gas companies after dead migratory birds were found near reserve pits associated with drilling activities. While the Department of Interior under the Trump administration has determined that such “incidental takes” of migratory birds do not violate the Act, this position was overruled by a federal district court in New York in August 2020. Nevertheless, on January 7, 2021, the Department of the Interior issued a rule which excluded incidental takes from the definition of prohibited activities under the Act. This rule was short-lived, however, and in October 2021, the Department of the Interior issued a rule to reverse the agency's position on incidental takes. The reversal took effect on December 3, 2021. The identification or designation of previously unprotected species as threatened
or endangered in areas where underlying property operations are conducted could cause REPX to incur increased costs arising from species protection measures or could result in limitations on REPX’s development activities that could have an adverse impact on REPX’s ability to develop and produce reserves. If REPX were to have a portion of its leases designated as critical or suitable habitat, it could adversely impact the value of REPX’s leases.
OSHA, Emergency Response and Community Right-to-Know, and Risk Management Planning
REPX is subject to the requirements of the Occupational Safety and Health Act (“OSHA”) and comparable state statutes whose purpose is to protect the health and safety of workers. In addition, the OSHA hazard communication standard, the Emergency Planning and Community Right-to-Know Act, the general duty clause and Risk Management Planning regulations promulgated under section 112(r) of the CAA and comparable state statutes and any implementing regulations require that REPX organizes and/or discloses information about hazardous materials used or produced in REPX’s operations and that this information be provided to employees, state and local governmental authorities and citizens. These laws also require the development of risk management plans for certain facilities to prevent accidental releases of extremely hazardous substances and to minimize the consequences of such releases should they occur.
Related Permits and Authorizations
Many environmental laws require REPX to obtain permits or other authorizations from state and/or federal agencies before initiating certain drilling, construction, production, operation, or other oil and natural gas activities, and to maintain these permits and compliance with their requirements for on-going operations. These permits are generally subject to protest, appeal, or litigation, which can in certain cases delay or halt projects and cease production or operation of wells, pipelines, and other operations.
Related Insurance
REPX maintains insurance against some risks associated with above or underground contamination that may occur as a result of REPX’s exploration 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 REPX. The occurrence of a significant event that is not fully insured or indemnified against could have a materially adverse effect on REPX’s financial condition and operations. Further, REPX has no coverage for gradual, long-term pollution events.
Facilities
Our land-based oil and natural gas processing facilities are typical of those found in the Permian Basin. Our facilities located at well locations or centralized lease locations include SWDs and associated gathering lines, storage tank batteries, oil/gas/water separation equipment and pumping equipment. In addition, we own a substantial majority of the electrical power infrastructure on our acreage position, which include power distribution lines and equipment.
Human Capital
As of December 31, 2022, we employed 65 people. We operate in a technical industry and depend on a highly skilled workforce in multiple disciplines including engineering, geology, operations, land, information technology, accounting and various other corporate functions.The Company supports its employees in pursuing training opportunities to enhance their professional skills. We are not a party to any collective bargaining agreements with our employees. We understand that employee recruiting, retention and development plays a critical role to our business activities and our ability to achieve our long-term strategy. We believe our relations with our employees to be satisfactory. From time to time we utilize the services of independent contractors to perform various field and other services.
Compensation and Benefits Program
The Company annually reviews compensation for all employees to adjust compensation for market conditions and attract and retain a highly skilled workforce. In addition to cash and equity compensation, the Company also offers other employee benefits such as life and health (medical, dental and vision) insurance, paid time off, and a 401(k) plan.
Diversity and Inclusion
We believe that diversity of backgrounds, experience and perspectives contributes to an innovative workforce and an enriching environment for our employees. We are committed to fostering an inclusive, respectful environment and providing equal opportunity to all qualified persons in our hiring, development, and compensation practices.
Community Involvement
The Company is dedicated to being a good neighbor in its operating areas. The Company provides support through various events, organizations, initiatives and partnerships.
Health, Safety and Environment
Protecting our employees, contractors, the public and the environment is a key focus for Riley Permian. The Company maintains a culture of continuous improvement in safety and environmental practices, supports a diverse workforce and inspires teamwork to drive innovation. We identify and mitigate safety risks and integrate a culture of safety by operating according to OSHA standards, processes, and procedures. We also strive to comply with all applicable health, safety and environmental standards, laws and regulations.
Available Information
Our corporate headquarters are located at 29 E. Reno Avenue, Suite 500, Oklahoma City, Oklahoma 73104, and the phone number at this address is (405) 415-8699. Our annual reports on Form 10-K, quarterly reports on Form 10-Q and/or 10-QT, current reports on Form 8-K and all amendments to those reports are available free of charge on our website, www.rileypermian.com, as soon as reasonably practicable after such material is electronically filed with, or furnished to, the SEC. Information contained on, or connected to, our website is not incorporated by reference into this Annual Report and should not be considered part of this or any other report that we file with or furnish to the SEC.
Item 1A. Risk Factors
The Company 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. Other risks are described in Item 1 and 2. Business and Properties, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations and Item 7A. Quantitative and Qualitative Disclosures About Market Risk. We could also face additional risks and uncertainties not currently known to us or that we currently deem to be immaterial. If any of these risks actually occurs, it could materially harm our business, financial condition or results of operations and the trading price of our shares could decline. Investors should carefully consider each of the following risk factors and all of the other information set forth in this Form 10-K.
Risks Related to our Business, Operations, and Strategy
Recent regulatory restrictions on use of produced water and a moratorium on new produced water disposal wells in the Permian Basin to stem rising seismic activity and earthquakes could increase our operating costs and adversely impact our business, results of operations and financial condition.
In September 2021, the RRC curtailed the amount of produced water companies were permitted to inject into some wells near Midland and Odessa in the Permian Basin, and has since indefinitely suspended some permits there and expanded the restrictions to other areas. These actions were taken in an effort to control induced seismic activity and recent increases in earthquakes in the Permian Basin, which have been linked by the U.S. and local seismologists to wastewater disposal in oil fields. These restrictions on the disposal of produced water and a moratorium on new produced water disposal wells could result in increased operating costs, requiring us or our service providers to truck produced water, recycle it or dispose of it by other means, all of which could be costly. We or our service providers may also need to limit disposal well volumes, disposal rates and pressures or locations, or require us or our service providers to shut down or curtail the injection of produced water into disposal wells. These factors may make drilling activity in the affected parts of the Permian Basin less economical and adversely impact our business, results of operations and financial condition.
Enhanced scrutiny on ESG matters could have an adverse effect on the Company’s operations.
Enhanced scrutiny on ESG matters related to, among other things, concerns raised by advocacy groups about climate change, hydraulic fracturing, natural gas flaring, GHG emissions, waste disposal, oil spills, and explosions of natural gas transmission pipelines may lead to increased regulatory scrutiny, which may, in turn, lead to new state and federal safety and environmental laws, regulations, guidelines, and enforcement interpretations. These actions may cause operational delays or restrictions, increased operating costs, additional regulatory burdens, increased risk of litigation, and adverse impacts on the Company’s access to capital. Moreover, governmental authorities exercise considerable discretion in the timing and scope of permit issuance, and the public may engage in the permitting process, including through intervention in the courts. Negative public perception could cause the permits the Company requires to conduct its operations to be withheld, delayed, or burdened by requirements that restrict the Company’s ability to profitably conduct its business.
We may be unable to quickly adapt to changes in market/investor priorities.
Historically, one of the key drivers in the unconventional resource industry has been growth in production and reserves. With historical volatility in oil and natural gas prices and the likelihood that rising interest rates will increase the cost of borrowing, capital efficiency and free cash flow from earnings have become the key drivers for energy companies, particularly shale producers. Such shifts in focus sometimes require changes in planning and resource management, which may not occur instantaneously. Any delay in responding to such changes in market sentiment or perception may result in the investment community having a negative sentiment regarding our business plan, potential profitability and our ability to operate in a manner deemed "efficient," which may have a negative impact on the price of our common stock.
Oil, natural gas, and NGL prices are volatile. An extended decline in commodity prices may adversely affect our business, financial condition, or results of operations and our ability to meet our capital expenditure obligations and financial commitments. Additionally, the value of our reserves calculated using SEC pricing may be higher than the fair market value of our reserves calculated using current market prices.
The prices we receive for our oil, natural gas, and NGL production heavily influence our revenue, profitability, access to capital, and future rate of growth. Oil, natural gas, and NGLs are commodities and, therefore, their prices are subject to wide fluctuations in response to relatively minor changes in supply and demand. Historically, the commodities market has been volatile. For example, during the period from January 1, 2016 to December 31, 2022, NYMEX West Texas Intermediate (referred to as WTI) oil prices ranged from a high of $123.64 per Bbl on March 8, 2022 to a low of $(36.98) per Bbl on April 20, 2020. During 2022, WTI prices ranged from a high of $123.64 to a low of $71.05 per Bbl. Average daily prices for NYMEX Henry Hub gas ranged from a high of $9.85 per MMBtu to a low of $3.46 per MMBtu during 2022. If the prices of oil and natural gas continue to be volatile, reverse their recent increases, or decline, our operations, financial condition, cash flows and level of expenditures may be materially and adversely affected. Moreover, the duration and magnitude of any decline in oil, natural gas or NGL prices cannot be predicted with accuracy, and this market will likely continue to be volatile in the future. The prices we receive for our production, and the levels of our production, depend on numerous factors beyond our control. These factors include the following:
•worldwide and regional economic conditions impacting the global supply and demand for oil, natural gas, and NGLs;
•the price and quantity of foreign imports, including foreign oil;
•the actions by members of OPEC+;
•political, economic, and military conditions in or affecting other producing countries, including embargoes or conflicts in the Middle East, Africa, South America and Russia;
•the level of global oil and natural gas exploration and production activity;
•the level of global oil and natural gas inventories;
•prevailing prices on local price indices in the areas in which we operate;
•the cost of producing and delivering oil and natural gas and conducting other operations;
•the recovery rates of new oil, natural gas and NGL reserves;
•lead times associated with acquiring equipment and products, and availability of qualified personnel;
•late deliveries of supplies;
•technical difficulties or failures;
•the proximity, capacity, cost, and availability of gathering and transportation facilities;
•localized and global supply and demand fundamentals and transportation availability;
•localized and global weather conditions;
•public health concerns such as pandemic diseases;
•technological advances affecting energy consumption, including advances in exploration, development and production technologies;
•shareholder activism or activities by non-governmental organizations to restrict the exploration, development and production of oil, natural gas, and NGLs;
•uncertainty in capital and commodities markets and the ability of companies in our industry to raise equity capital and debt financing;
•the price and availability of alternative fuels; and
•domestic, local, and foreign governmental regulation and taxes.
Lower commodity prices will reduce our cash flows and borrowing ability. We may be unable to obtain needed capital or financing on satisfactory terms, which could lead to a decline in the present value of our reserves and our ability to develop future reserves. Lower commodity prices may also reduce the amount of oil, natural gas and NGLs that we can produce economically. We have historically been able to hedge our oil and natural gas production at prices that are significantly higher than current strip prices. However, in the current commodity price environment, our ability to enter into comparable derivative arrangements may be limited, and, in the future, we will not be under an obligation to hedge a specific portion of our oil or natural gas production.
Using lower prices in estimating proved reserves would likely result in a reduction in proved reserve volumes due to economic limits. While it is difficult to project future economic conditions and whether such conditions will result in impairment of proved property costs, we consider several variables including 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. In addition, sustained periods with oil and natural gas prices at levels lower than current West Texas Intermediate strip prices and the resultant effect such prices may have on our drilling economics and our ability to raise capital may require us to re-evaluate and postpone or eliminate our development drilling, which could result in the reduction of some of our proved undeveloped reserves and related standardized measure. If we are required to curtail our drilling program, we may be unable to continue to hold leases that are scheduled to expire, which may further reduce our reserves. As a result, a substantial or extended decline in commodity prices may materially and adversely affect our future business, financial condition, results of operations, liquidity, or ability to finance planned capital expenditures.
If commodity prices decrease to a level such that our future undiscounted cash flows from our properties are less than their carrying value for a significant period of time, we will be required to take write-downs of the carrying values of our properties.
Accounting rules require that we periodically review the carrying value of our properties for possible impairment. Based on 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 write down the carrying value of our properties. A write down constitutes a non-cash charge to earnings. If market or other economic conditions deteriorate or if oil, natural gas and NGL prices decline, we may incur impairment charges, which may have a material adverse effect on our results of operations.
Our exploration and development projects require substantial capital expenditures. We may be unable to obtain required capital or financing on satisfactory terms, which could 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 exploitation, development, and acquisition of oil and natural gas reserves. We expect to fund our growth primarily through cash flow from operations, availability under our revolving credit facility, and subsequent equity or debt offerings when appropriate. The actual amount and timing of our future capital expenditures may differ materially from our estimates as a result of, among other things, oil, natural gas and NGL prices, actual drilling results, the availability of drilling rigs and other services and equipment, and regulatory, technological and competitive developments. A reduction in commodity prices from current levels may result in a decrease in our actual capital expenditures, which would negatively impact our ability to grow production.
Our cash flow from operations and access to capital are subject to a number of variables, including:
•our proved reserves;
•the level of hydrocarbons we are able to produce from existing wells and the timing of such production;
•the prices at which our production is sold;
•operating costs and other expenses;
•the availability of takeaway capacity;
•credit facility and/or investor requirements;
•our ability to acquire, locate and produce new reserves; and
•our ability to borrow under our revolving credit facility.
If our revenue or the borrowing base under our revolving credit facility decreases as a result of lower oil, natural gas and NGL 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. If cash flow generated by our operations or available borrowings under our revolving credit facility are not sufficient to meet our capital requirements, 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.
Our development and exploratory drilling efforts and our well operations may not be profitable or achieve our targeted returns.
We have acquired 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 provide assurance that all prospects will be economically viable or that we will not abandon our undeveloped acreage. 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 that we decide to drill may not yield oil, natural gas or NGLs in commercially viable quantities.
Our prospects are in various stages of evaluation, ranging from prospects that are currently being drilled, to prospects that will require substantial additional seismic data processing and interpretation. Properties that we decide to drill that do not yield oil, natural gas or NGLs in commercially viable quantities will adversely affect our results of operations and financial condition. There is no way to predict in advance of drilling and testing whether any particular prospect will yield oil or natural gas in sufficient quantities to recover drilling or completion costs or to be economically viable. The use of micro-seismic data and other technologies and the study of producing fields in the same area will not enable us to know conclusively prior to drilling whether oil or natural gas will be present or, if present, whether oil or natural gas will be present in commercial quantities. We cannot assure you that the analogies we draw from available data from other wells, more fully explored prospects or producing fields will be applicable to our drilling prospects. Further, our drilling operations may be curtailed, delayed or cancelled as a result of numerous factors, including:
•unexpected drilling conditions;
•title problems;
•pressure or lost circulation in formations;
•equipment failure or accidents;
•adverse weather conditions;
•compliance with environmental and other governmental or contractual requirements; and
•increase in the cost of, shortages or delays in the availability of, electricity, supplies, materials, drilling or workover rigs, equipment and services.
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 liabilities, including environmental liabilities. Such
assessments are inexact and inherently uncertain. For these reasons, the properties we have acquired or will acquire in the future may not produce as projected or may be more costly to operate than projected. 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 review every well, pipeline or associated facility. We cannot necessarily observe structural and environmental problems, such as pipe corrosion or groundwater contamination, when a review is performed. We may be unable to obtain contractual indemnities from the seller for liabilities created prior to our purchase of the property. We may be required to assume the risk of the physical condition of the properties in addition to the risk that the properties may not perform in accordance with our expectations.
Reserve estimates depend on many assumptions that may turn out to be inaccurate. Any material inaccuracies in reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves.
The process of estimating oil and natural gas reserves is complex. It requires interpretations of available technical data and many assumptions, including assumptions relating to current and future economic conditions and commodity prices. Any significant inaccuracies in these interpretations or assumptions could materially affect the estimated quantities and present value of our reserves.
In order to prepare reserve estimates, we must project production rates and timing of development expenditures. We must also analyze available geological, geophysical, production and engineering data. The extent, quality and reliability of this data can vary. The process also requires economic assumptions about matters such as oil, natural gas and NGL prices, drilling and operating expenses, capital expenditures, taxes, and availability of funds.
Actual future production, oil, natural gas and NGL prices, revenues, taxes, development expenditures, operating expenses, and quantities of recoverable oil and natural gas reserves will vary from our estimates. Any significant variance could materially affect the estimated quantities and present value of our reserves. In addition, we may revise reserve estimates to reflect production history, results of exploration and development, existing commodity prices and other factors, many of which are beyond our control.
The present value of future net revenues from our reserves should not be assumed to represent the current market value of our estimated reserves. We generally base the estimated discounted future net cash flows from reserves on prices and costs on the date of the estimate. Actual future prices and costs may differ materially from those used in the present value estimate. For example, our estimated proved reserves as of December 31, 2022 were calculated under SEC rules using the unweighted arithmetic average first-day-of-the-month prices for the prior 12 months of $94.14 per Bbl for oil and NGL volumes and $6.36 per MMBtu for natural gas volumes. Using lower prices in estimating proved reserves would likely result in a reduction in proved reserve volumes due to economic limits.
There is a limited amount of production data from horizontal wells completed in the Permian Basin and its San Andres Formation. As a result, reserve estimates associated with horizontal wells in this area are subject to greater uncertainty than estimates associated with reserves attributable to vertical wells in the same area.
Reserve engineers rely in part on the production history of nearby wells in establishing reserve estimates for a particular well or field. Horizontal drilling in the San Andres Formation of the Permian Basin is a relatively recent development, whereas vertical drilling has been utilized by producers in this area for over 50 years. As a result, the amount of production data from horizontal wells available to reserve engineers is relatively small compared to that of production data from vertical wells. Until a greater number of horizontal wells have been completed in the San Andres Formation, and a longer production history from these wells has been established, there may be a greater variance in our proved reserves on a year-over-year basis due to the transition from vertical to horizontal reserves in both the proved developed and proved undeveloped categories. Such variance could be material and any such variance could have a material and adverse impact on our cash flows and results of operations.
Part of our strategy involves drilling using the latest available horizontal drilling and completion techniques, which involve risks and uncertainties in their application.
Our operations involve utilizing the latest drilling and completion techniques as developed by us and our service providers. As of December 31, 2022, we have drilled and completed 170 gross operated horizontal wells on our West Texas and New Mexico acreage, and therefore are subject to increased risks associated with horizontal drilling as compared to companies that have greater experience in horizontal drilling activities. Risks that we face while drilling include, but are not limited to, failing to land our wellbore in the desired drilling zone, not staying in the desired drilling zone while drilling horizontally through the formation, not running our casing the entire length of the wellbore and not being able to run tools and other equipment
consistently through the horizontal wellbore. Risks that we face while completing our wells include, but are not limited to, not being able to fracture stimulate the planned number of stages, not being able to run tools the entire length of the wellbore during completion operations and not successfully cleaning out the wellbore after completion of the final fracture stimulation stage.
Additionally, certain of the new techniques we are adopting may cause irregularities or interruptions in production due to offset wells being shut in and the time required to drill and complete multiple wells before any such wells begin producing.
Ultimately, the success of these drilling and completion techniques can only be evaluated over time as more wells are drilled and production profiles are established over a sufficient time period. If our drilling results are less than anticipated or we are unable to execute our drilling program because of capital constraints, lease expirations, access to gathering systems, and/or commodity prices decline, the return on our investment in these areas may not be as attractive as we anticipate. Further, as a result of any of these developments we could incur material write-downs of our oil and natural gas properties and the value of our undeveloped acreage could decline in the future.
Approximately 11% of our net leasehold acreage is undeveloped and that acreage may not ultimately be developed or become commercially productive, which could cause us to lose rights under our leases as well as have a material adverse effect on our oil and natural gas reserves and future production and, therefore, our future cash flow and income.
Oil and natural gas leases generally must be drilled before the end of the lease term or the leaseholder will lose the lease and any capital invested therein. In addition, leases may also be lost due to legal issues relating to the ownership of leases. Any delays in drilling or legal issues causing us to lose leases on properties could have a material adverse effect on our results of operations and reserve growth.
As of December 31, 2022, approximately 11% of our net leasehold acreage was undeveloped or acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and natural gas regardless of whether such acreage contains proved reserves. Unless production is established on the undeveloped acreage covered by our leases, such leases will expire. Our future oil and natural gas reserves and production and, therefore, our future cash flow and income are highly dependent on successfully developing our undeveloped leasehold acreage.
Our drilling plans are subject to change based upon various factors, including factors that are beyond our control. Such factors include drilling results, oil and natural gas prices, the availability and cost of capital, drilling and production costs, availability of drilling services and equipment, gathering system and pipeline transportation constraints, and regulatory approvals. If our leases expire, we will lose our right to develop such properties.
Substantially all of our producing properties are located in the Northwest Shelf within the Permian Basin of West Texas, making us vulnerable to risks associated with operating in one major geographic area. Specifically, as the Permian Basin is an area of high industry activity, we may be unable to hire, train, or retain qualified personnel needed to manage and operate our assets.
Substantially all of our producing properties are geographically concentrated in the Northwest Shelf sub-basin within the Permian Basin of West Texas, an area in which industry activity has increased rapidly. At December 31, 2022, the majority of our total estimated proved reserves were attributable to properties located in this area. As a result of this concentration, a number of our properties could experience any of the same conditions at the same time and, when compared to other companies that have a more diversified portfolio of properties, we may be disproportionately exposed to the impact of regional supply and demand factors, delays or interruptions of production from wells in this area caused by governmental regulation, processing or transportation capacity constraints, market limitations, water shortages or other drought or extreme weather related conditions or interruption of the processing or transportation of oil, natural gas or NGLs.
Specifically, demand for qualified personnel in this area, and the cost to attract and retain such personnel, may increase substantially in the future. Moreover, our competitors, including those operating in multiple basins, may be able to offer better compensation packages to attract and retain qualified personnel than we are able to offer. Any delay or inability to secure the personnel necessary for us to continue or complete our current and planned development activities could have a negative effect on production volumes or significantly increase costs, which could have a material adverse effect on our results of operations, liquidity and financial condition.
In addition, the geographic concentration of our assets including our total estimated proved reserves as of December 31, 2022, exposes us to additional risks, such as changes in field-wide rules and regulations that could cause us to permanently or temporarily shut-in all of our wells within a field.
Our drilling and production programs may not be able to obtain access on commercially reasonable terms or otherwise to truck transportation, pipelines, gas gathering, transmission, storage and processing facilities to market our oil and natural gas production, certain of which we do not control, and our initiatives to expand our access to midstream and operational infrastructure may be unsuccessful.
The marketing of oil and natural gas production depends in large part on the capacity and availability of pipelines and storage facilities, trucks, gas gathering systems and other transportation, processing and refining facilities. Access to such facilities is, in many respects, beyond our control. If these facilities are unavailable to us on commercially reasonable terms or otherwise, we could be forced to shut in some production or delay or discontinue drilling plans and commercial production following a discovery of hydrocarbons. We rely (and expect to rely in the future) on facilities developed and owned by third parties in order to store, process, transmit, and sell our oil and natural gas production. Our plans to develop and sell our oil and natural gas reserves, the expected results of our drilling program and our cash flow and results of operations could be materially and adversely affected by the inability or unwillingness of third parties to provide sufficient facilities and services to us on commercially reasonable terms or otherwise. The amount of oil and natural gas that can be produced is subject to limitation in certain circumstances, such as pipeline interruptions due to scheduled and unscheduled maintenance, excessive pressure, damage to the gathering, transportation, refining or processing facilities, or lack of capacity on such facilities. For example, increases in activity in the Permian Basin could contribute to bottlenecks in processing and transportation that may negatively affect our results of operations, and these adverse effects could be disproportionately severe to us compared to our more geographically diverse competitors.
Similarly, the concentration of our assets within a small number of producing formations exposes us to risks, such as changes in field-wide rules, which could adversely affect development activities or production relating to those formations. In addition, in areas where exploration and production activities are increasing, as has been the case in recent years in the Permian Basin, we are subject to increasing competition for drilling rigs, oilfield equipment, services, supplies and qualified personnel, which may lead to periodic shortages or delays. The curtailments arising from these and similar circumstances may last from a few days to several months, and in many cases, we may be provided only limited, if any, notice as to when these circumstances will arise and their duration.
While we have undertaken initiatives to expand our access to midstream and operational infrastructure, these initiatives may be delayed or unsuccessful. As a result, our business, financial condition, and results of operations could be adversely affected.
The prices we receive for our production may be affected by local and regional factors.
The prices we receive for our production will be determined to a significant extent by factors affecting the local and regional supply of and demand for oil and natural gas, including the adequacy of the pipeline and processing infrastructure in the region to process and transport our production and that of other producers. Those factors result in basis differentials between the published indices generally used to establish the price received for regional oil and natural gas production and the actual price we receive for our production, which may be lower than index prices. If the price differentials pursuant to which our production is subject were to widen due to oversupply or other factors, our revenue could be negatively impacted.
An increase in the differential between NYMEX WTI and the reference or regional index price used to price our oil and natural gas would reduce our cash flows from operations.
Our oil and natural gas is priced in the local markets where it is produced based on local or regional supply and demand factors. The prices we receive for our oil and natural gas are typically lower than the relevant benchmark prices, such as NYMEX WTI. The difference between the benchmark price and the price we receive is called a differential. Numerous factors may influence local pricing, such as pipeline capacity and processing infrastructure. Additionally, insufficient pipeline or transportation capacity, lack of demand in any given operating area or other factors may cause the differential to increase in a particular area compared with other producing areas. For example, production increases from competing Permian Basin producers, combined with limited pipeline and transportation capacity in the area, have gradually widened differentials in the Permian Basin.
For the year ended December 31, 2022, our realized oil differential to NYMEX WTI averaged $(2.05) per Bbl of oil and our realized natural gas differential to NYMEX Henry Hub averaged $(3.12) per Mcf of gas. Given that a significant amount of our production is from the Permian Basin, if the negative price differential in the Permian Basin increases, we expect that the effect of our price differential on our revenues will also increase. Increases in the differential between the benchmark prices for
oil and natural gas, such as the NYMEX WTI and NYMEX Henry Hub, and the realized price we receive could significantly reduce our revenues and our cash flow from operations.
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 37% of our total estimated proved reserves were classified as proved undeveloped. Our approximate 28,551 MBoe of estimated proved undeveloped reserves are estimated to require $324.4 million of development capital. Our development of these reserves may take longer and require higher levels of capital expenditures than we currently anticipate. The actual amount and timing of our future capital expenditures may differ materially from our estimates as a result of, among other things, oil, natural gas and NGL prices, actual drilling results, the availability of drilling rigs and other services and equipment, and regulatory, technological and competitive developments. We expect to fund our growth primarily through cash flow from operations, availability under our revolving credit facility, and subsequent equity or debt offerings when appropriate. 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. In addition, delays in the development of reserves could cause us to have to reclassify our proved undeveloped reserves as unproved reserves.
We participate in oil and natural gas leases with third parties who may not be able to fulfill their commitments to our projects.
We own less than 100% of the working interest in the oil and natural gas leases on which we conduct operations, and other parties will own the remaining portion of the working interest. Financial risks are inherent in any operation where the cost of drilling, equipping, completing and operating wells is shared by more than one person. We could be held liable for joint activity obligations of other working interest owners, such as nonpayment of costs and liabilities arising from the actions of other working interest owners. In addition, declines in oil, natural gas and NGL 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, may be unable to access debt or equity financing, and, in some cases, may declare bankruptcy. In the event any of our project partners do not pay their share of such costs, we would likely have to pay those costs, and we may be unsuccessful in any efforts to recover these costs from our partners, which could materially adversely affect our financial position.
We own non-operating interests in properties developed and operated by third parties and, as a result, we are unable to control the operation and profitability of such properties.
We participate in the drilling and completion of wells with third-party operators that exercise exclusive control over such operations. As a participant, we rely on the third-party operators to successfully operate these properties pursuant to joint operating agreements and other similar contractual arrangements.
As a participant in these operations, we may not be able to maximize the value associated with these properties in the manner we believe appropriate, or at all. For example, we cannot control the success of drilling and development activities on properties operated by third parties, which depend on a number of factors under the control of a third-party operator, including such operator’s determinations with respect to, among other things, the nature and timing of drilling and operational activities, the timing and amount of capital expenditures and the selection of suitable technology. In addition, the third-party operator’s operational expertise and financial resources and its ability to gain the approval of other participants in drilling wells will impact the timing and potential success of drilling and development activities in a manner that we are unable to control. A third-party operator’s failure to adequately perform operations, breach of the applicable agreements or failure to act in ways that are favorable to us could reduce our production and revenues, negatively impact our liquidity and cause us to spend capital in excess of our current plans, and have a material adverse effect on our financial condition and results of operations.
Unless we replace our reserves with new reserves and develop those reserves, our reserves and production will decline, which would adversely affect our future cash flows and results of operations.
Producing oil and natural gas reservoirs generally are characterized by declining production rates that vary depending upon reservoir characteristics and other factors. Unless we conduct successful ongoing exploitation, development and exploration activities or continually acquire properties containing proved reserves, our proved reserves will decline as those reserves are produced. Our future reserves and production, and therefore our future cash flow and results of operations, are highly dependent
on our success in efficiently developing and exploiting our current reserves and economically finding or acquiring additional recoverable reserves. We may not be able to develop, exploit, find or acquire sufficient additional reserves to replace our current and future production. If we are unable to replace our current and future production, the value of our reserves will decrease, and our business, financial condition and results of operations would be adversely affected.
We depend upon several significant purchasers for the sale of most of our oil and natural gas production. The loss of one or more of these purchasers could, among other factors, limit our access to suitable markets for the oil, natural gas and NGLs we produce.
The availability of a ready market for any oil, natural gas and NGLs we produce depends on numerous factors beyond the control of our management, including but not limited to the extent of domestic production and imports of oil, the proximity and capacity of pipelines, the availability of skilled labor, materials and equipment, the effect of state and federal regulation of oil and natural gas production and federal regulation of oil and gas sold in interstate commerce. In addition, we depend upon several significant purchasers for the sale of most of our oil and natural gas production. We cannot assure you that we will continue to have ready access to suitable markets for our future oil and natural gas production.
We have exposure to credit risk through receivables from purchasers of our oil, natural gas and NGL production. One purchaser accounted for 89% of our revenues for the year ended December 31, 2022. This concentration of purchasers may impact our overall credit risk in that this purchaser may be similarly affected by changes in economic conditions or commodity price fluctuations. We do not require our customers to post collateral. The inability or failure of our significant purchaser to meet their obligations to us or their insolvency or liquidation may materially adversely affect our financial condition and results of operations.
We may incur substantial losses and be subject to substantial liability claims as a result of our operations. Additionally, we may not be insured for, or our insurance may be inadequate to protect us against, these risks.
Our operations are subject to inherent risks, some of which are beyond our control. We are not insured against all risks. Losses and liabilities arising from uninsured and under insured events could materially and adversely affect our business, financial condition or results of operations.
Our exploration and production activities are subject to all of the operating risks associated with drilling for and producing oil and natural gas, including the risk of fire, explosions, blowouts, surface cratering or other cratering, uncontrollable flows of natural gas, oil, well fluids and formation water, pipe or pipeline failures, abnormally pressured formations, casing collapses, reservoir damage and environmental hazards such as oil, produced water or chemical spills, natural gas leaks, ruptures or discharges of toxic gases.
Any of these risks could adversely affect our ability to conduct operations or result in substantial loss to us as a result of claims for:
•injury or loss of life;
•employee/employer liabilities and risks, including wrongful termination, discrimination, labor organizing, retaliation claims, and general human resource related matters;
•damage to and destruction of property, natural resources and equipment;
•pollution and other environmental hazards or damage;
•abnormally pressured formations, fires or explosions or natural disasters;
•mechanical difficulties, such as stuck oil field drilling and service tools and casing collapse;
•regulatory investigations and penalties;
•landowner claims for property damage and restoration costs;
•suspension of our operations; and repair and remediation costs;
•repair and remediation costs.
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. Claims for loss of oil and natural gas production and damage to formations can occur in our industry. Litigation arising from a catastrophic occurrence at a location where our systems are deployed may result in our being named as a defendant in lawsuits asserting large claims.
Moreover, insurance may not be available in the future at commercially reasonable costs and on commercially reasonable terms. Also, pollution and environmental risks generally are not fully insurable. The occurrence of an event that is not covered
or fully covered by insurance and any delay in the payment of insurance proceeds for covered events could have a material adverse effect on our business, financial condition and results of operations.
We may be unable to make accretive acquisitions or successfully integrate acquired businesses or assets, and any inability to do so may disrupt our business and hinder our ability to grow.
In the future we may make acquisitions of oil and natural gas properties or businesses that complement or expand our current business. The successful acquisition of oil and natural gas properties requires an assessment of several factors, including:
•recoverable reserves;
•future oil, natural gas and NGL prices and their applicable differentials;
•estimates of operating costs;
•estimates future development costs;
•estimates of the costs and timing of plugging and abandonment; and
•environmental and other liabilities.
The accuracy of these assessments is inherently uncertain, and we may not be able to identify accretive acquisition opportunities. In connection with these assessments, we perform a review of the subject properties that we believe to be generally consistent with industry practices. Our review will not reveal all existing or potential problems nor will it permit us to become sufficiently familiar with the properties to assess fully their deficiencies and capabilities. Reviews may not always be performed on every well, and environmental problems, such as subsurface or groundwater contamination, are not necessarily observable even when a review is performed. Even when problems are identified, the seller may be unwilling or unable to provide effective contractual protection against all or part of the problems. We often are not entitled to contractual indemnification for environmental liabilities and acquire properties on an “as is” basis. Even if we do identify accretive acquisition opportunities, we may not be able to complete the acquisition or do so on commercially acceptable terms.
The success of any completed acquisition will depend on our ability to integrate effectively the acquired business into our existing operations. The process of integrating acquired businesses may involve unforeseen difficulties and may require a disproportionate amount of our managerial and financial resources. In addition, possible future acquisitions may be larger and for purchase prices significantly higher than those paid for earlier acquisitions. No assurance can be given that we will be able to identify additional suitable acquisition opportunities, negotiate acceptable terms, obtain financing for acquisitions on acceptable terms or successfully acquire identified targets. Our failure to achieve consolidation savings, to integrate the acquired businesses and assets into our existing operations successfully or to minimize any unforeseen operational difficulties could have a material adverse effect on our financial condition and results of operations.
In addition, our revolving credit facility imposes certain limitations on our ability to enter into mergers or combination transactions as well as limits our ability to incur certain indebtedness, which could indirectly limit our ability to engage in acquisitions.
We may incur losses as a result of title defects in the properties in which we invest.
It is our practice in acquiring oil and natural gas leases or interests not to incur the expense of retaining lawyers to examine the title to the mineral interest at the time of acquisition. Rather, we rely upon the judgment of lease brokers or land men who perform the fieldwork in examining records in the appropriate governmental office before attempting to acquire a lease in a specific mineral interest. The existence of a material title deficiency can render a lease worthless and can adversely affect our results of operations and financial condition. While we do typically obtain title opinions prior to commencing drilling operations on a lease or in a unit, the failure of title may not be discovered until after a well is drilled, in which case we may lose the lease and the right to produce all or a portion of the minerals under the property.
Our operations could be impacted by burdens and encumbrances on title to our properties.
Our leasehold and other acreage may be subject to existing oil and natural gas leases, liens for current taxes and other burdens, including other mineral encumbrances and restrictions customary in the oil and natural gas industry. Such liens and burdens could materially interfere with the use or otherwise affect the value of such properties. Additionally, any cloud on the title of the working interests, leases and other rights owned by us could have a material adverse effect on our operations.
Our undeveloped acreage must be drilled before lease expirations to hold the acreage by production or by other operations. In highly competitive markets for acreage, failure to drill sufficient wells to hold acreage could result in a substantial lease renewal cost or, if renewal is not feasible, loss of our lease and prospective drilling opportunities.
Unless production is established within the spacing units covering the undeveloped acres on which some of our drilling locations are identified, our leases for such acreage will expire. As of December 31, 2022, 61% of our net undeveloped acreage is set to expire through 2023, before taking into account the expected drilling of wells and holding leases by production, while 12% of our net undeveloped acreage is set to expire through 2023, after taking into account the expected drilling of wells and holding leases by production. We intend to extend or renew any core lease we plan to develop or are still assessing for development that is set to expire in 2023 and expect to incur $0.6 million to extend or renew those leases, after taking into account the expected drilling of wells and holding leases by production. Where we do not have the option to extend a lease, however, we may not be successful in negotiating extensions or renewals. Our ability to drill and develop our core acreage and establish production to maintain our leases depends on a number of uncertainties, including oil, natural gas and NGL prices, the availability and cost of capital, drilling and production costs, availability of drilling services and equipment, drilling results, lease expirations, gathering system and pipeline transportation constraints, access to and availability of water sourcing and distribution systems, regulatory approvals and other factors. The cost to renew such leases may increase significantly, and we may not be able to renew such leases on commercially reasonable terms or at all. As such, our actual drilling activities may differ materially from our current expectations, which could adversely affect our business. These risks are greater at times and in areas where the pace of our exploration and development activity slows.
We plan to use CO2 for our EOR projects. Our production from these EOR operations may decline if we are not able to obtain sufficient amounts of CO2.
Oil production from our EOR projects depends on, among other factors, having access to sufficient amounts of CO2 from our third party suppliers of CO2. Our ability to produce oil from our EOR projects would be hindered if the supply of CO2 was limited due to, among other things, physical limitations on CO2 supply or the ability to economically procure CO2 at costs low enough to ensure the economic viability of our EOR projects. This could have a material adverse effect on our financial condition, results of operations or cash flows. Future oil production from the Company’s EOR projects is dependent on the timing, volumes and location of CO2 injections and, in particular, our ability to obtain sufficient volumes of CO2. Market conditions may cause the delay or cancellation of the development of naturally occurring CO2 sources or construction of plants that produce anthropogenic CO2 as a byproduct that can be purchased, thus limiting the amount of CO2 available for use in our EOR projects.
Our use of 2-D and 3-D seismic data is subject to interpretation and may not accurately identify the presence of oil and natural gas, which could adversely affect the results of our drilling operations.
Even when properly used and interpreted, 2-D and 3-D seismic data and visualization techniques are only tools used to assist geoscientists in identifying subsurface structures and hydrocarbon indicators and do not enable the interpreter to know whether hydrocarbons are, in fact, present in those structures. In addition, the use of 3-D seismic and other advanced technologies requires greater predrilling expenditures than traditional drilling strategies, and we could incur losses as a result of such expenditures. As a result, our drilling activities may not be successful or economical.
Our acquisition strategy will subject us to certain risks associated with the inherent uncertainty in evaluating properties for which we have limited information.
We intend to continue to expand our operations in part through acquisitions. Our decision to acquire properties will depend in part on the evaluation of data obtained from production reports and engineering studies, geophysical and geological analyses and seismic and other information, the results of which are often inconclusive and subject to various interpretations. Also, our reviews of acquired properties are inherently incomplete because it generally is not economically feasible to perform an in-depth review of the individual properties involved in each acquisition. Even a detailed review of records and properties may not necessarily reveal existing or potential problems, nor will it permit us to become sufficiently familiar with the properties to assess fully their deficiencies and potential. Inspections are often not performed on properties being acquired, and environmental matters, such as subsurface contamination, are not necessarily observable even when an inspection is undertaken.
Any acquisition involves other potential risks, including, among other things:
•the validity of our assumptions about reserves, future production, revenues and costs;
•a decrease in our liquidity by using a significant portion of our cash from operations or borrowing capacity to finance acquisitions;
•a significant increase in our interest expense or financial leverage if we incur additional debt to finance acquisitions;
•the ultimate value of any contingent consideration agreed to be paid in an acquisition;
•dilution to stockholders if we use equity as consideration for, or to finance, acquisitions;
•the assumption of unknown liabilities, losses or costs for which we are not indemnified or for which our indemnity is inadequate;
•an inability to hire, train or retain qualified personnel to manage and operate our growing business and assets; and
•an increase in our costs or a decrease in our revenues associated with any potential royalty owner or landowner claims or disputes, or other litigation encountered in connection with an acquisition.
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 and future acquisitions.
Acquisitions of assets or businesses may reduce, rather than increase, our distributable cash flow or may disrupt our business.
Even if we make acquisitions that we believe will be accretive, these acquisitions may nevertheless result in a decrease in our cash flow. Any acquisition involves potential risks that may disrupt our business, including the following, among other things:
•mistaken assumptions about volumes or the timing of those volumes, revenues or costs, including synergies;
•an inability to successfully integrate the acquired assets or businesses;
•the assumption of unknown liabilities;
•exposure to potential lawsuits;
•limitations on rights to indemnity from the seller;
•the diversion of management’s and employees’ attention from other business concerns;
•unforeseen difficulties operating in new geographic areas; and
•customer or key employee losses at the acquired businesses.
We may need to access funding through capital market transactions. Due to our small public float, low market capitalization, limited operating history, ESG, and climate change restrictions, it may be difficult and expensive for us to raise additional funds.
We may need to raise funds through the issuance of shares of our common stock or securities linked to our common stock. Our ability to raise these funds may be dependent on a number of factors, including the risk factors further described herein and the low trading volume and volatile trading price of our shares of common stock. The stocks of small cap companies tend to be highly volatile. We expect that the price of our common stock will be highly volatile for the next several years.
As a result, we may be unable to access funding through sales of our common stock or other equity-linked securities. Even if we were able to access funding, the cost of capital may be substantial due to our low market cap and small public float. The terms of any funding we are able to obtain may not be favorable to us and may be highly dilutive to our stockholders. We may be unable to access capital due to unfavorable market conditions or other market factors outside of our control such as ESG and/or climate change restrictions. There can be no assurance that we will be able to raise additional capital when needed. The failure to obtain additional capital when needed would have a material adverse effect on our business.
Our revolving credit facility has substantial restrictions and financial covenants that may restrict our business and financing activities and our ability to declare dividends.
The operating and financial restrictions and covenants in our revolving credit facility restrict, and any future financing agreements likely will restrict, our ability to finance future operations or capital needs, engage, expand or pursue our business
activities or pay dividends. Our revolving credit facility restricts, and any future financing agreements likely will restrict, its ability to, among other things:
•incur indebtedness;
•issue certain equity securities, including preferred equity securities;
•incur certain liens or permit them to exist;
•engage in certain fundamental changes, including mergers or consolidations;
•make certain investments, loans, advances, guarantees and acquisitions;
•sell or transfer assets;
•enter into sale and leaseback transactions;
•redeem or repurchase shares from our stockholders;
•pay dividends to our stockholders unless the net leverage ratio, after giving effect to pro forma adjustments, does not exceed 2.0 to 1.0, the total revolving credit exposures under our revolving credit facility are not greater than 80% of the total revolving commitments, and no default or event of default then exists or would exist upon the payment of the dividend;
•make certain payments of junior indebtedness;
•enter into certain types of transactions with our affiliates;
•enter into certain restrictive agreements; and
•enter into swap agreements and hedging arrangements.
Our ability to comply with these restrictions and covenants in the future is uncertain and will be affected by the levels of free cash flow and events or circumstances beyond our control, such as a downturn in our business or the economy in general or reduced oil, natural gas and NGL prices. A failure to comply with the provisions of our revolving credit facility could result in a default or an event of default that could enable our lenders to declare the outstanding principal of that debt, together with accrued and unpaid interest, to be immediately due and payable. Further, our ability to pay dividends to our stockholders will be restricted and our lenders’ commitment to make further loans to us may terminate. We might not have, or be able to obtain, sufficient funds to make these accelerated payments, and our common stock holders could experience a partial or total loss of their investment. In addition, our obligations under our revolving credit facility are secured by substantially all of our assets, and if we are unable to repay our indebtedness under our revolving credit facility, the lenders can seek to foreclose on our assets.
Our indebtedness could reduce our financial flexibility.
The level of our indebtedness could affect our operations in several ways, including the following:
•a significant portion of our cash flow could be used to service the indebtedness;
•a high level of debt would increase our vulnerability to general adverse economic and industry conditions;
•the covenants contained in our revolving credit facility limit our ability to borrow additional funds, dispose of assets, pay dividends and make certain investments; and
•a high level of debt could impair our ability to obtain additional financing in the future for working capital, capital expenditures, acquisitions, general corporate purposes, or other purposes.
Any significant reduction in our borrowing base under our revolving credit facility as a result of the periodic borrowing base redeterminations or otherwise may negatively impact our ability to fund our operations.
Our revolving credit facility limits the amounts we can borrow up to a borrowing base amount, which the lenders, in their sole discretion, determine in accordance with the terms of the agreement. The borrowing base depends on, among other things, projected revenues from, and asset values of, the proved oil and natural gas properties securing our loan. The value of our proved reserves is dependent upon, among other things, the prevailing and expected market prices of the underlying commodities in our estimated reserves. A further reduction or sustained decline in oil, natural gas and NGL prices could adversely affect our business, financial condition and results of operations, and our ability to meet our capital expenditure obligations and financial commitments. Reserve estimates depend on many assumptions that may turn out to be inaccurate. Any material inaccuracies in reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves. We could be forced to repay a portion of our bank borrowings or transfer to the lenders additional collateral due to redeterminations of our borrowing base that result in a reduction of the available revolving commitments. If we are forced to do so, we may not have sufficient funds to make such repayments or provide such collateral. If we do not have sufficient funds and are otherwise unable to negotiate renewals of our borrowings, provide additional collateral or arrange new financing, we may have to sell significant assets. Any such sale could have a material adverse effect on our business and financial results.
In the future, we may not be able to access adequate funding under our revolving credit facility as a result of a decrease in borrowing base due to the issuance of new indebtedness, the outcome of a subsequent borrowing base redetermination or an unwillingness or inability on the part of lending counterparties to meet their funding obligations and the inability of other lenders to provide additional funding to cover the defaulting lender’s portion. Declines in commodity prices could result in a redetermination and reduction of the borrowing base in the future and, in such a case, we could be required to repay any indebtedness in excess of the reduced borrowing base. As a result, we may be unable to implement our drilling and development plan, make acquisitions or otherwise carry out business plans, which would have a material adverse effect on our financial condition and results of operations and impair our ability to service our indebtedness.
We may not be able to generate sufficient cash to service all of our indebtedness and may be forced to take other actions to satisfy our obligations under our debt arrangements, which may not be successful.
Our ability to make scheduled payments on or to refinance our indebtedness obligations depends on our financial condition and operating performance, which are subject to prevailing economic and competitive conditions and certain financial, business and other factors beyond our control. If our cash flows and capital resources are insufficient to fund debt service obligations, we may be forced to reduce or delay investments and capital expenditures, sell assets, seek additional capital, or restructure or refinance indebtedness. Our ability to restructure or refinance indebtedness will depend on the condition of the capital markets and our financial condition at such time. Any refinancing of indebtedness could be at higher interest rates and may require us to comply with more onerous covenants, which could further restrict business operations. The terms of our existing revolving credit facility or future debt arrangements may restrict us from adopting some of these alternatives. In addition, any failure to make payments of interest and principal on outstanding indebtedness on a timely basis could harm our ability to incur additional indebtedness. In the absence of sufficient cash flows and capital resources, we could face substantial liquidity problems and might be required to dispose of material assets or operations to meet debt service and other obligations. Our revolving credit facility currently restricts our ability to dispose of assets and our use of the proceeds from such dispositions. We may not be able to consummate those dispositions, and the proceeds of any such disposition may not be adequate to meet any debt service obligations then due. These alternative measures may not be successful and may not permit us to meet scheduled debt service obligations.
In addition, we will require significant additional capital over a prolonged period in order to pursue the development of these locations, and we may not be able to raise or generate the capital required to do so. Any drilling activities we are able to conduct on these potential locations may not be successful or result in our ability to add additional proved reserves to our overall proved reserves or may result in a downward revision of our estimated proved reserves, which could have a material adverse effect on our future business and results of operations.
Our derivative activities could result in financial losses or could reduce our earnings.
We enter or may enter into commodity derivative contracts for a portion of our production, primarily consisting of swaps, put options and call options. We purchase such derivatives to achieve more predictable cash flows, to reduce our exposure to adverse fluctuations in the prices of oil, natural gas, and NGLs, and in order to remain in compliance with covenants in our revolving credit facility. Accordingly, our earnings may fluctuate significantly as a result of changes in fair value of our derivative instruments.
Derivative instruments also can expose us to the risk of financial loss in some circumstances, including when:
•production is less than the volume covered by the derivative instruments;
•the counterparty to the derivative instrument defaults on its contractual obligations;
•there is an increase in the differential between the underlying price in the derivative instrument and actual prices received; or
•there are issues with regard to legal enforceability of such instruments.
The use of derivatives may, in some cases, require the posting of cash collateral with counterparties. If we enter into derivative instruments that require cash collateral and commodity prices or interest rates change in a manner adverse to us, our cash otherwise available for use in our operations would be reduced, which could limit our ability to make future capital expenditures and make payments on our indebtedness, and which could also limit the size of our borrowing base. Future collateral requirements will depend on arrangements with our counterparties, highly volatile oil, natural gas, and NGL prices and interest rates. In addition, derivative arrangements could limit the benefit we would receive from increases in the prices for oil, natural gas, and NGLs, which could also have an adverse effect on our financial condition.
Our commodity derivative contracts expose us to risk of financial loss if a counterparty fails to perform under a contract. Disruptions in the financial markets could lead to sudden decreases in a counterparty’s liquidity, which could make them unable to perform under the terms of the contract and we may not be able to realize the benefit of the contract. We are unable to predict sudden changes in a counterparty’s creditworthiness or ability to perform. Even if we do accurately predict sudden changes, our ability to negate the risk may be limited depending upon market conditions.
During periods of declining commodity prices, our derivative contract receivable positions could generally increase, which increases our counterparty credit exposure. If the creditworthiness of our counterparties deteriorates and results in their nonperformance, we could incur a significant loss with respect to our commodity derivative contracts.
Risks Related to the Oil and Natural Gas Industry
Drilling for and producing oil and natural gas are high risk activities with many uncertainties that could adversely affect our business, financial condition or results of operations.
Our future financial condition and results of operations will depend on the success of our exploitation, development, and acquisition activities, which are subject to numerous risks beyond our control, including the risk that drilling will not result in commercially viable oil and natural gas production.
Our decisions to purchase, explore, develop, or otherwise exploit prospects or properties will depend in part on the evaluation of data obtained through geophysical and geological analyses, production data, and engineering studies, the results of which are often inconclusive or subject to varying interpretations. Any material inaccuracies in reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves.” In addition, our cost of drilling, completing, and operating wells is often uncertain before drilling commences.
Further, many factors may curtail, delay, or cancel our scheduled drilling projects, including the following:
•delays and increased costs imposed by or resulting from compliance with environmental and other regulatory requirements including limitations on or resulting from wastewater discharge and disposal, subsurface injections, greenhouse gas emissions, and hydraulic fracturing;
•pressure or irregularities in geological formations;
•increases in the cost of, or shortages or delays in availability of drilling rigs and qualified personnel for hydraulic fracturing activities;
•shortages of or delays in obtaining water resources, suitable proppant, and chemicals in sufficient quantities for use in hydraulic fracturing activities;
•equipment failures or accidents;
•lack of available gathering facilities or delays in construction of gathering facilities;
•lack of available capacity on interconnecting transmission pipelines;
•adverse weather conditions, such as tornadoes, droughts, ice storms, and extreme freeze events;
•lack of available treatment or disposal options for oil and natural gas waste, including produced water;
•environmental hazards, such as oil and natural gas leaks, oil spills, pipeline and tank ruptures, encountering naturally occurring radioactive materials, and unauthorized discharges of brine, well stimulation and completion fluids, toxic gases or other pollutants into the surface and subsurface environment;
•issues related to permitting under and compliance with environmental and other governmental regulations;
•declines or volatility in oil, natural gas, and NGL prices;
•limited availability of financing at acceptable terms;
•title problems or legal disputes regarding leasehold rights; and
•limitations in the market for oil, natural gas, and NGLs.
Conservation measures and technological advances could reduce demand for oil, natural gas and NGLs.
Our industry is characterized by rapid and significant technological advancements and introductions of new products and services using new technologies. Fuel and other energy conservation measures, alternative fuel requirements, increasing consumer demand for alternatives to oil, natural gas and NGLs, technological advances in fuel economy and energy generation devices could reduce demand for oil, natural gas and NGLs. As competitors and others use or develop new technologies or technologies comparable to ours in the future, we may lose market share or be placed at a competitive disadvantage. Further, we may face competitive pressure to implement or acquire certain new technologies at a substantial cost. Some of our competitors may have greater financial, technical and personnel resources than we do, which may allow them to gain technological
advantages or implement new technologies before we can. Additionally, we may be unable to implement new technologies or services at all, on a timely basis or at an acceptable cost. Limits on our ability to effectively use, implement or adapt to new technologies may have a material adverse effect on our business, financial condition and results of operations. Similarly, the impact of the changing demand for oil and natural gas services and products may have a material adverse effect on our business, financial condition, results of operations and cash flows.
Limitation or restrictions on our ability to obtain water may have an adverse effect on our operating results.
Water is an essential component of shale and conventional oil and natural gas development during both the drilling and hydraulic fracturing processes. Our access to water to be used in these processes may be adversely affected due to reasons such as periods of extended drought, private, third party competition for water in localized areas or the implementation of local or state governmental programs to monitor or restrict the beneficial use of water subject to their jurisdiction for hydraulic fracturing to assure adequate local water supplies. In addition, treatment and disposal of flowback and produced water is becoming more highly regulated and restricted. Thus, our costs for obtaining and disposing of water could increase significantly. Our inability to locate or contractually acquire and sustain the receipt of sufficient amounts of water could adversely impact our exploration and production operations and have a corresponding adverse effect on our business, results of operations and financial condition.
The unavailability or high cost of equipment, supplies, personnel and oilfield services used to drill and complete wells could adversely affect our ability to execute our development plans within our budget and on a timely basis.
The demand for drilling rigs, pipe and other equipment and supplies, as well as for qualified and experienced field personnel to drill wells and conduct field operations, geologists, geophysicists, engineers and other professionals in the oil and natural gas industry, can fluctuate significantly, often in correlation with oil and natural gas prices, causing periodic shortages. Our operations are concentrated in areas in which activity has increased rapidly, and as a result, demand for such drilling rigs, equipment and personnel, as well as access to transportation, processing and refining facilities in these areas, has increased, as have the costs for those items. In addition, to the extent our suppliers source their products or raw materials from foreign markets, the cost of such equipment could be impacted if the United States imposes tariffs on imported goods from countries where these goods are produced. Such shortages or cost increases could delay or cause us to incur significant expenditures that are not provided for in our capital budget, which could have a material adverse effect on our business, financial condition or results of operations.
Competition in the oil and natural gas industry is intense, making it more difficult for us to acquire properties and market oil or natural gas.
Our ability to acquire additional prospects and to find and develop reserves in the future will depend on our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment for acquiring properties, marketing oil and natural gas and securing trained personnel. Also, there is substantial competition for capital available for investment in the oil and natural gas industry. We may not be able to compete successfully in the future in acquiring prospective reserves, developing reserves, marketing hydrocarbons, and raising additional capital, which could have a material adverse effect on our business.
Declining general economic, business or industry conditions have, and will continue to have, a material adverse effect on our results of operations, liquidity and financial condition, and are expected to continue having a material adverse effect for the forseeable future.
Concerns over global economic conditions, the threat of pandemic diseases and the results thereof, energy costs, geopolitical issues, inflation, the availability and cost of credit have contributed to increased economic uncertainty and diminished expectations for the global economy. These factors, combined with volatile prices of oil and natural gas, declining business and consumer confidence, and increased unemployment, have precipitated an economic slowdown and a recession, which could expand to a global depression. Concerns about global economic growth have had a significant adverse impact on global financial markets and commodity prices and are expected to continue having a material adverse effect for the foreseeable future. If the economic climate in the United States or abroad continues to deteriorate, demand for petroleum products could diminish, which could further impact the price at which our operators can sell oil, natural gas, and NGLs, affect the ability of our vendors, suppliers and customers to continue operations, and ultimately adversely impact our results of operations, liquidity and financial condition to a greater extent than it has already. In addition, a decline in consumer confidence or changing patterns in the availability and use of disposable income by consumers can negatively affect the demand for oil and natural gas as a result of our results of operations.
Continuing or worsening inflationary issues and associated changes in monetary policy have resulted in and may result in additional increases to the cost of our goods, services and personnel, which in turn cause our capital expenditures and operating costs to rise.
Inflation has been an ongoing concern in the U.S. since 2021. Ongoing inflationary pressures have resulted in and may result in additional increases to the costs of goods, services and personnel, which in turn cause our capital expenditures and operating costs to rise. Sustained levels of high inflation caused the U.S. Federal Reserve and other central banks to increase interest rates multiple times in 2022 in an effort to curb inflationary pressure on the costs of goods and services, which could have the effects of raising the cost of capital and depressing economic growth, either of which (or the combination thereof) could hurt the financial and operating results of our business. We may experience further cost increases for our operations to the extent that elevated inflation remains.
We may not be able to keep pace with technological developments in our industry.
The oil and natural gas industry is characterized by rapid and significant technological advancements and introductions of new products and services using new technologies. As others use or develop new technologies, we may be placed at a competitive disadvantage or may be forced by competitive pressures to implement those new technologies at substantial costs. In addition, other oil and natural gas companies may have greater financial, technical and personnel resources that allow them to enjoy technological advantages and that may in the future allow them to implement new technologies before we can. We may not be able to respond to these competitive pressures or implement new technologies on a timely basis or at an acceptable cost. If one or more of the technologies we use now or in the future were to become obsolete, our business, financial condition or results of operations could be materially and adversely affected.
Negative public perception regarding us and/or our industry could have an adverse effect on our operations.
Negative public perception regarding us and/or our industry resulting from, among other things, concerns raised by advocacy groups about hydraulic fracturing, oil spills, seismic activity, greenhouse gas emissions, and explosions of natural gas transmission lines may lead to increased regulatory scrutiny, which may, in turn, lead to new state and federal safety and environmental laws, regulations, guidelines and enforcement interpretations. These actions may cause operational delays or restrictions, increased operating costs, additional regulatory burdens and increased risk of litigation. Moreover, governmental authorities exercise considerable discretion in the timing and scope of permit issuance and the public may engage in the permitting process, including through intervention in the courts. Negative public perception could cause the permits we need to conduct our operations to be withheld, delayed, or burdened by requirements that restrict our ability to profitably conduct our business.
Risks Related to Acts of God and Cyber Security
Power outages, limited availability of electrical resources, and increased energy costs could have a material adverse effect on us.
Our operations are subject to electrical power outages, regional competition for available power, and increased energy costs. Power outages, which may last beyond our backup and alternative power arrangements, would harm our operations and our business.
We also may be subject to risks and unanticipated costs associated with obtaining power from various utility companies. Such utilities may be dependent on, and sensitive to price increases for, a particular type of fuel, such as coal, oil or natural gas. The price of these fuels and the electricity generated from them could increase as a result of proposed legislative measures related to climate change or efforts to regulate carbon or other greenhouse gas emissions.
Extreme weather conditions could adversely affect our ability to conduct drilling activities in the areas where we operate.
Our exploration, exploitation and development activities and equipment could be adversely affected by extreme weather conditions, such as floods, lightening, drought, ice and other storms, prolonged freeze events, and tornadoes, which may cause a loss of production from temporary cessation of activity or lost or damaged facilities and equipment. Such extreme weather conditions could also impact other areas of our operations, including 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 electrical power, water, gathering, processing, compression and transportation services. These constraints and the resulting shortages or
high costs could delay or temporarily halt our operations and materially increase our operation and capital costs, which could have a material adverse effect on our business, financial condition and results of operations.
Our business could be negatively affected by security threats, including cybersecurity threats, and other disruptions.
The oil and natural gas industry has become increasingly dependent on digital technologies to conduct day-to-day operations. For example, the industry depends on digital technologies to interpret seismic data, manage drilling rigs, production equipment and gathering systems, conduct reservoir modeling and reserves estimation, and process and record financial and operating data. At the same time, cyber incidents, including deliberate attacks or unintentional events, have increased. As an oil and natural gas producer, our technologies, systems, networks, and those of our business partners, may become the target of cyberattacks or information security breaches that could result in the unauthorized release, misuse, loss or destruction of proprietary and other information, or other disruption of business operations that could lead to disruptions in critical systems, unauthorized release of confidential or otherwise protected information, and corruption of data. We face various security threats, including cybersecurity threats to gain unauthorized access to sensitive information or to render data or systems unusable; threats to the security of our facilities and infrastructure or third party facilities and infrastructure, such as processing plants and pipelines; and threats from terrorist acts. The potential for such security threats has subjected our operations to increased risks that could have a material adverse effect on our business. In particular, our implementation of various procedures and controls to monitor and mitigate security threats and to increase security for our information, facilities and infrastructure may result in increased capital and operating costs. Moreover, there can be no assurance that such procedures and controls will be sufficient to prevent security breaches from occurring. If any of these security breaches were to occur, they could lead to losses of sensitive information, critical infrastructure or capabilities essential to our operations and could have a material adverse effect on our reputation, financial position, results of operations or cash flows. Cybersecurity attacks in particular are becoming more sophisticated and include, but are not limited to, malicious software, attempts to gain unauthorized access to data and systems, and other electronic security breaches that could lead to disruptions in critical systems, unauthorized release of confidential or otherwise protected information, and corruption of data. These events could lead to financial losses from remedial actions, loss of business or potential liability.
Loss of our information and computer systems could adversely affect our business.
We are dependent on our information systems and computer-based programs, including our well operations information, seismic data, electronic data processing and accounting data. If any of such programs or systems were to fail or create erroneous information in our hardware or software network infrastructure, possible consequences include our loss of communication links, inability to find, produce, process and sell oil and natural gas and inability to automatically process commercial transactions or engage in similar automated or computerized business activities. Any such consequence could have a material adverse effect on our business.
A Terrorist attack or armed conflict could harm our business.
Terrorist activities, anti-terrorist efforts and other armed conflicts involving the United States or other countries may adversely affect the United States and global economies and could prevent us from meeting our financial and other obligations. If any of these events occur, the resulting political instability and societal disruption could reduce overall demand for oil and natural gas causing a reduction in our revenues. Oil and natural gas related facilities could be direct targets of terrorist attacks, and our operations could be adversely impacted if infrastructure integral to our customers’ operations is destroyed or damaged. Costs for insurance and other security may increase as a result of these threats, and some insurance coverage may become more difficult to obtain, if available at all.
Risks Related to Legal, Regulatory, and Tax Matters
We are subject to stringent federal, state and local laws and regulations related to environmental and occupational health and safety issues that could adversely affect the cost, manner or feasibility of conducting our operations or expose us to significant liabilities.
Our operations are subject to stringent federal, state and local laws and regulations governing occupational safety and health aspects of our operations, the discharge of materials into the environment and environmental and human health protection. These laws and regulations may impose numerous obligations applicable to our operations including (i) the acquisition of a permit before conducting drilling, production, and other regulated activities; (ii) the restriction of types, quantities and concentration of materials that may be released into the environment; (iii) the limitation or prohibition of drilling activities on certain lands lying within wilderness, wetlands, protected species habitat, and other protected areas; (iv) the
application of specific health and safety criteria addressing worker protection; (v) the imposition of substantial liabilities for pollution resulting from our operations; (vi) the installation of costly emission monitoring and/or pollution control equipment; and (vii) the reporting of the types and quantities of various substances that are generated, stored, processed, or released in connection with our properties. Numerous governmental authorities, such as the U.S. Environmental Protection Agency, or EPA, the U.S. Fish and Wildlife Service, and analogous state agencies, and state oil and natural gas commissions, such as the Railroad Commission of Texas, have the power to enforce compliance with these laws and regulations and the permits issued under them. Such enforcement actions often involve taking difficult and costly compliance measures or corrective actions. Failure to comply with these laws and regulations may result in the assessment of sanctions, including administrative, civil or criminal penalties, the imposition of investigatory or remedial obligations, and the issuance of orders limiting or prohibiting some or all of our operations. In addition, we may experience delays in obtaining or be unable to obtain required permits, which may delay or interrupt our operations or specific projects and limit our growth and revenue.
There is inherent risk of incurring significant environmental costs and liabilities in the performance of our operations due to our handling of petroleum hydrocarbons and other hazardous substances and wastes, as a result of air emissions and wastewater discharges related to our operations, and because of historical operations and waste disposal practices at our leased and owned properties, as well as locations where waste from our operations is transported offsite for disposal. Spills or other releases of regulated substances, including such spills and releases that occur in the future, could expose us to material losses, expenditures and liabilities under applicable environmental laws and regulations. Under certain of such laws and regulations, we could be subject to strict, joint and several liability for the removal or remediation of previously released materials or property contamination, regardless of whether we were responsible for the release or contamination and even if our operations met previous standards in the industry at the time they were conducted. We may not be able to recover some or any of these costs from insurance. Changes in environmental laws and regulations occur frequently and tend to become more stringent over time, and any changes that result in more stringent or costly well drilling, construction, completion or water management activities, air emissions control or waste handling, storage, transport, disposal or cleanup requirements could require us to make significant expenditures to attain and maintain compliance and may otherwise have a material adverse effect on our results of operations, competitive position or financial condition. For example, on October 1, 2015, the EPA issued a final rule under the CAA, lowering the NAAQS, for ground-level ozone from the current standard of 75 parts per billion, or ppb, for the current 8-hour primary and secondary ozone standards to 70 ppb for both standards. Subsequently, the EPA designated over 200 counties across the U.S. as “nonattainment” for these standards, meaning that new and modified stationary emissions sources in these areas are subject to more stringent permitting and pollution control requirements. On December 23, 2021, the EPA announced its decision to retain, without changes, the 2015 NAAQs. If our operations become subject to these more stringent standards, compliance with these and other environmental regulations could delay or prohibit our ability to obtain permits for operations or require us to install additional pollution control equipment, the costs of which could be significant.
We are subject to complex laws that can affect the cost, manner or feasibility of doing business.
Exploration, development, production and sale of oil and natural gas are subject to extensive federal, state, local and international regulation. We may be required to make large expenditures to comply with governmental regulations. Matters subject to regulation include:
•permits for drilling operations;
•drilling bonds;
•reports concerning operations;
•the spacing of wells;
•the rates of production;
•the plugging and abandoning of wells;
•unitization and pooling of properties; and
•taxation.
Under these laws, we could be liable for property damage and other damages. Failure to comply with these laws also may result in the suspension or termination of our operations and subject us to administrative, civil and criminal penalties. Moreover, these laws could change in ways that substantially increase our costs. Any such liabilities, penalties, suspensions, terminations or regulatory changes could materially adversely affect our financial condition and results of operations.
We are responsible for the decommissioning, plugging, abandonment, and reclamation costs for our facilities.
We are responsible for compliance with all applicable laws and regulations regarding the decommissioning, plugging, abandonment, and reclamation of our facilities at the end of their economic life, the costs of which may be substantial. It is not possible to predict these costs with certainty since they will be a function of regulatory requirements at the time of decommissioning, plugging, abandonment, and reclamation. We may, in the future, determine it prudent or be required by applicable laws or regulations to establish and fund one or more decommissioning, plugging, abandonment, and reclamation reserve funds to provide for payment of future decommissioning, plugging, abandonment, and reclamation costs, which could decrease funds available to service debt obligations. In addition, such reserves, if established, may not be sufficient to satisfy such future decommissioning, plugging, abandonment, and reclamation costs and we will be responsible for the payment of the balance of such costs.
SEC rules could limit our ability to book additional proved undeveloped reserves in the future.
SEC rules require that, subject to limited exceptions, proved undeveloped reserves, or PUDs, may only be booked if they relate to wells scheduled to be drilled within five years after the date of booking. This requirement has limited and may continue to limit our ability to book additional PUDs as we pursue our drilling program. Moreover, we may be required to write down our PUDs if we do not drill or plan on delaying those wells within the required five-year timeframe.
Should we fail to comply with all applicable regulatory agency administered statutes, rules, regulations and orders, we could be subject to substantial penalties and fines.
Under the Energy Policy Act of 2005, FERC has substantial enforcement authority to prohibit the manipulation of natural gas markets and enforce its rules and orders, including civil penalty authority under the NGA to impose penalties for current violations of up to $1.0 million per day for each violation. FERC may also impose administrative and criminal remedies and disgorgement of profits associated with any violation. While our operations have not been regulated by FERC as a natural gas company under the NGA, FERC has adopted regulations that may subject certain of our otherwise non-FERC jurisdictional facilities to FERC annual reporting requirements. We also must comply with the anti-market manipulation rules enforced by FERC. Additional rules and regulations pertaining to those and other matters may be considered or adopted by FERC from time to time. Additionally, the Federal Trade Commission (the “FTC”) has regulations intended to prohibit market manipulation in the petroleum industry with authority to fine violators of the regulations civil penalties of up to $1.0 million per day, and the CFTC, prohibits market manipulation in the markets regulated by the CFTC, including similar anti-manipulation authority with respect to oil swaps and futures contracts as that granted to the CFTC with respect to oil purchases and sales. The CFTC rules subject violators to a civil penalty of up to the greater of $1.0 million or triple the monetary gain to the person for each violation. Failure to comply with those regulations in the future could subject us to civil penalty liability, as described in “Business—Regulation of the Oil and Gas Industry.”
A change in the jurisdictional characterization of our natural gas assets by federal, state or local regulatory agencies or a change in policy by those agencies may result in increased regulation of our natural gas assets, which may cause our revenues to decline and operating expenses to increase.
Section 1(b) of the NGA exempts natural gas gathering facilities from the jurisdiction of FERC. We believe that our natural gas gathering pipelines meet the traditional test that FERC has used to determine whether a pipeline is a gathering pipeline and is, therefore, not subject to FERC jurisdiction. The distinction between FERC-regulated transmission services and gathering services not subject to the jurisdiction of FERC, however, has been the subject of substantial litigation, and FERC determines whether facilities are gathering facilities on a case-by-case basis, so the classification and regulation of our gathering facilities is subject to change based on future determinations by FERC, the courts or Congress. If FERC were to consider the status of an individual facility and determine that the facility or services provided by it are not exempt from FERC regulation under the NGA and that the facility provides interstate service, the rates for, and terms and conditions of, services provided by such facility would be subject to regulation by FERC under the NGA or the NGPA.
Such regulation could decrease revenue and increase operating costs. In addition, if any of our facilities were found to have provided services or otherwise operated in violation of the NGA or NGPA, this could result in the imposition of substantial civil penalties, as well as a requirement to disgorge revenues collected for such services in excess of the maximum rates established by FERC.
FERC regulation may indirectly impact gathering services not directly subject to FERC regulation. FERC’s policies and practices across the range of its natural gas regulatory activities, including, for example, its policies on interstate open access
transportation, ratemaking, capacity release, and market center promotion may indirectly affect intrastate markets. In recent years, FERC has pursued procompetitive policies in its regulation of interstate natural gas pipelines. However, we cannot assure you that FERC will continue to pursue this approach as it considers matters such as pipeline rates and rules and policies that may indirectly affect the natural gas gathering services.
Natural gas gathering may receive greater regulatory scrutiny at the state level; therefore, our natural gas gathering operations could be adversely affected should they become subject to the application of state regulation of rates and services. State regulation of gathering facilities generally includes various safety, environmental and, in some circumstances, nondiscriminatory take requirements and complaint-based rate regulation. Our gathering operations could also be subject to safety and operational regulations relating to the design, construction, testing, operation, replacement and maintenance of gathering facilities.
We may be involved in legal proceedings that could result in substantial liabilities.
We may, from time to time, be a claimant or defendant to various legal proceedings, disputes and claims arising in the course of our business, including those that arise from interpretation of federal and state laws and regulations affecting the natural gas and crude oil industry, personal injury claims, title disputes, royalty disputes, contract claims, contamination claims relating to oil and natural gas exploration and development and environmental claims, including claims involving assets previously sold to third parties and no longer part of our current operations. Such legal 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. 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.
Federal, state and local legislative and regulatory initiatives relating to hydraulic fracturing as well as governmental reviews of such activities could result in increased costs and additional operating restrictions or delays in the completion of oil and natural gas wells and adversely affect our production.
Hydraulic fracturing is an important and common practice that is used to stimulate production of natural gas and/or oil from dense subsurface rock formations. We regularly use hydraulic fracturing as part of our operations. Hydraulic fracturing involves the injection of water, sand or alternative proppant and chemicals under pressure into targeted geological formations to fracture the surrounding rock and stimulate production. Hydraulic fracturing is typically regulated by state oil and natural gas commissions. However, several federal agencies have asserted regulatory authority over certain aspects of the process.
For example, in February 2014, the EPA asserted regulatory authority pursuant to the SDWA UIC program over hydraulic fracturing activities involving the use of diesel and issued guidance covering such activities. Also, beginning in 2012, the EPA issued a series of regulations under the federal CAA that include NSPS, known as Subpart OOOO, for completions of hydraulically fractured natural gas wells and certain other plants and equipment and, in May 2016, published a final rule establishing new emissions standards, known as Subpart OOOOa, for methane and volatile organic compounds (“VOCs”) from certain new, modified and reconstructed equipment and processes in the oil and natural gas source category. The NSPS Subpart OOOO and OOOOa rules have since been subject to numerous legal challenges as well as EPA reconsideration proceedings and subsequent amendment proposals. Most recently, on September 14 and 15, 2020, EPA published two new rules in the Federal Register that remove the transmission and storage sectors of the oil and natural gas industry from regulation under the NSPS and rescind methane-specific standards for the production and processing segments of the industry. However, states and environmental groups brought suit challenging the new rules almost immediately, and in June 2021, Congress partially overturned the rollback. Furthermore, in November 2021 and November 2022, EPA issued proposed rules which would update, strengthen, and expand the NSPS Subpart OOOOa regulations for methane and VOC emissions from new, modified, and reconstructed sources. Notably, the proposed rules also include emissions guidelines to assist states in the development of plans to regulate methane emissions from certain existing sources. Legal challenges to the proposed rules are likely to follow, and accordingly, legal uncertainty exists with respect to the future scope and extent of implementation of the methane rule; however, even as currently implemented, these rules apply to our operations, including requirements for the installation of equipment to control VOC emissions from certain hydraulic fracturing of wells and fugitive emissions from well site and other production equipment, and additional regulation, which could result in significant costs, including increased capital expenditures and operating costs, and could adversely impact or delay oil and natural gas production activities, which could have a material adverse effect on our business.
The BLM published a final rule in March 2015 that established new or more stringent standards relating to hydraulic fracturing on federal and American Indian lands. However, following years of litigation, the BLM rescinded the rule in December 2017. The BLM and the Secretary of the U.S. Department of the Interior are now being sued for the decision to rescind the rule. In April 2020, the Northern District of California issued a ruling in favor of the BLM and the Department of the Interior. This ruling is now being appealed; thus, the future of the rule remains uncertain. Also, in December 2016, the EPA released its final report on the potential impacts of hydraulic fracturing on drinking water resources, concluding that “water cycle” activities associated with hydraulic fracturing may impact drinking water resources under certain circumstances.
From time to time, legislation has been introduced in Congress to provide for federal regulation of hydraulic fracturing and to require disclosure of the chemicals used in the hydraulic fracturing process but, to date, such legislation has not been adopted. At the state level, Texas, where we conduct our operations, is among the states that has adopted regulations that impose new or more stringent permitting, including the requirement for hydraulic-fracturing operators to complete and submit a list of chemicals used during the fracking process. We may incur significant additional costs to comply with such existing state requirements and, in the event additional state level restrictions relating to the hydraulic-fracturing process are adopted in areas where we operate, we may become subject to additional permitting requirements and experience added delays or curtailment in the pursuit of exploration, development, or production activities.
Moreover, we typically dispose of flowback and produced water or certain other oilfield fluids gathered from oil and natural gas producing operations in underground disposal wells. This disposal process has been linked to increased induced seismicity events in certain areas of the country, particularly in Oklahoma, Texas, Colorado, Kansas, New Mexico and Arkansas. These and other states have begun to consider or adopt laws and regulations that may restrict or otherwise prohibit oilfield fluid disposal in certain areas or underground disposal wells, and state agencies implementing these requirements may issue orders directing certain wells where seismic incidents have occurred to restrict or suspend disposal well operations or impose standards related to disposal well construction and monitoring. For example, in 2014, the RRC published a final rule governing permitting or re-permitting of disposal wells that would require, among other things, the submission of information on seismic events occurring within a specified radius of the disposal well location, as well as logs, geologic cross sections and structure maps relating to the disposal area in question. If the permittee or an applicant of a disposal well permit fails to demonstrate that the injected fluids are confined to the disposal zone or if scientific data indicates such a disposal well is likely to be or determined to be contributing to seismic activity, then the TRRC may deny, modify, suspend or terminate the permit application or existing operating permit for that well. Any one or more of these developments may result in our having to limit disposal well volumes, disposal rates or locations, or to cease disposal well activities, which could have a material adverse effect on our business, financial condition, and results of operations.
In addition, several cases have recently put a spotlight on the issue of whether injection wells may be regulated under the Federal Water Pollution Control Act (the “Clean Water Act” or “CWA”) if a direct hydrological connection to a jurisdictional surface water can be established. The split among federal circuit courts of appeals that decided these cases engendered two petitions for writ of certiorari to the United States Supreme Court in August 2018, one of which was granted in February 2019. The EPA has also brought attention to the reach of the CWA’s jurisdiction in such instances by issuing a request for comment in February 2018 regarding the applicability of the CWA permitting program to discharges into groundwater with a direct hydrological connection to jurisdictional surface water, which hydrological connections should be considered “direct,” and whether such discharges would be better addressed through other federal or state programs. In a statement issued by EPA in April 2019, the agency concluded that the CWA should not be interpreted to require permits for discharges of pollutants that reach surface waters via groundwater. However, in April 2020, the Supreme Court issued a ruling in the case, County of Maui, Hawaii v. Hawaii Wildlife Fund, holding that discharges into groundwater may be regulated under the CWA if the discharge is the “functional equivalent” of a direct discharge into navigable waters. On January 14, 2021, EPA issued guidance on the ruling, which emphasized that discharges to groundwater are not necessarily the “functional equivalent” of a direct discharge based solely on proximity to jurisdictional waters. However, on September 16, 2021, EPA rescinded its prior guidance. The U.S. Supreme Court’s ruling in County of Maui, Hawaii v. Hawaii Wildlife Fund could result in increased operational costs if permits are required under the CWA for disposal of our flowback and produced water in underground disposal wells.
Increased regulation and attention given to the hydraulic fracturing process and associated processes could lead to greater opposition to, and litigation concerning, oil and natural gas production activities using hydraulic fracturing techniques. Additional legislation or regulation could also lead to operational delays or increased operating costs in the production of oil and natural gas, including from developing shale plays, or could make it more difficult to perform hydraulic fracturing. The adoption of any federal, state or local laws or the implementation of regulations regarding hydraulic fracturing could potentially cause a decrease in the completion of new oil and natural gas wells and an associated increase in compliance costs and time, which could have a material adverse effect on our liquidity, results of operations, and financial condition.
Climate change legislation and regulations restricting or regulating emissions of greenhouse gases could result in increased operating costs and reduced demand for the oil, natural gas and NGLs that we produce while potential physical effects of climate change could disrupt our production and cause us to incur significant costs in preparing for or responding to those effects.
Climate change continues to attract considerable public and scientific attention. As a result, numerous proposals have been made and are likely to continue to be made at the international, national, regional, and state levels of government to monitor and limit emissions of GHGs. While no comprehensive climate change legislation has been implemented at the federal level, the EPA and states or groupings of states have pursued legal initiatives in recent years that seek to reduce GHG emissions through efforts that include consideration of cap-and-trade programs, carbon taxes, GHG reporting and tracking programs and regulations that directly limit GHG emissions from certain sources. In particular, the EPA has adopted rules under authority of the CAA that, among other things, establish certain permit reviews for GHG emissions from certain large stationary sources, which reviews could require securing permits at covered facilities emitting GHGs and meeting defined technological standards for those GHG emissions. The EPA has also adopted rules requiring the monitoring and annual reporting of GHG emissions from certain petroleum and natural gas system sources in the United States, including, among others, onshore production.
Federal agencies also have begun directly regulating emissions of methane, a GHG, from oil and natural gas operations. In June 2016, the EPA published a final rule establishing NSPS Subpart OOOOa, which requires certain new, modified or reconstructed facilities in the oil and natural gas sector to reduce these methane gas and VOC emissions. Although much of the initial rules remain intact and effective, the rules have been subject to legal challenges, reconsideration by EPA, stays, and proposed amendments. For example, on September 14 and 15, 2020, EPA published two new final rules in the Federal Register that remove the transmission and storage sectors of the oil and natural gas industry from regulation under the NSPS and rescind methane-specific standards for the production and processing segments of the industry. However, states and environmental groups brought suit challenging the new rules almost immediately, and in June 2021, Congress partially overturned the rollback. Furthermore, in November 2021 and November 2022, the EPA issued proposed rules which would update, strengthen, and expand the NSPS Subpart OOOOa regulations for methane and VOC emissions from new, modified, and reconstructed sources. Notably, the proposed rules also include emissions guidelines to assist states in the development of plans to regulate methane emissions from certain existing sources. The BLM also finalized rules regarding the control of methane emissions in November 2016 that applied to oil and natural gas exploration and development activities on public and tribal lands. The rules sought to minimize venting and flaring of emissions from storage tanks and other equipment, and also impose leak detection and repair requirements. However, due to subsequent BLM revisions and multiple legal challenges, the rules were never fully implemented, and in October 2020, the November 2016 rules were struck down by the District Court of Wyoming as the result of one such challenge. New Mexico and California have since filed an appeal of the Wyoming Court's decision in the Tenth Circuit. Additionally, in December 2015, the United States joined the international community at the 21st Conference of the Parties of the United Nations Framework Convention on Climate Change in Paris, France that prepared an agreement requiring member countries to review and “represent a progression” in their intended nationally determined contributions, which set GHG emission reduction goals every five years beginning in 2020. This “Paris Agreement” was signed by the United States in April 2016 and entered into force in November 2016; however, this agreement does not create any binding obligations for nations to limit their GHG emissions. Nevertheless, President Biden has set ambitious targets for GHG reduction, including to achieve at least a 50 percent reduction from 2005 levels in economy-wide net GHG pollution by 2030.
The adoption and implementation of any international, federal or state legislation or regulations that require reporting of GHGs or otherwise restrict emissions of GHGs could result in increased compliance costs or additional operating restrictions, and could have a material adverse effect on our business, financial condition, results of operations, and cash flows.
In addition, spurred by increasing concerns regarding climate change, the oil and natural gas industry faces growing demand for corporate transparency and a demonstrated commitment to sustainability goals. ESG goals and programs, which typically include extralegal targets related to environmental stewardship, social responsibility, and corporate governance, have become an increasing focus of investors and shareholders across the industry. While reporting on ESG metrics remains voluntary, access to capital and investors is likely to favor companies with robust ESG programs in place.
Finally, increasing concentrations of GHG in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, droughts, floods and other climatic events. If any such climatic events were to occur, they could have an adverse effect on our financial condition and results of operations and the financial condition and operations of our customers.
Increases in interest rates could adversely affect our business.
Our business and operating results can be harmed by factors such as the availability, terms and cost of capital, increases in interest rates or a reduction in credit rating. These changes could cause our cost of doing business to increase, limit our ability to pursue acquisition opportunities, reduce cash flow used for drilling, and place us at a competitive disadvantage. Potential disruptions and volatility in the global financial markets may lead to a contraction in credit availability impacting our ability to finance our operations. We require continued access to capital. A significant reduction in cash flows from operations or the availability of credit could materially and adversely affect our ability to achieve our planned growth and operating results.
Restrictions on drilling or other operational activities intended to protect certain species of wildlife may adversely affect our ability to conduct drilling activities in areas where we operate.
Oil and natural gas operations in our operating areas may be adversely affected by seasonal or permanent restrictions on drilling activities designed to protect various wildlife. 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 or materially increase our operating and capital costs. Permanent restrictions imposed to protect threatened or endangered species and their habitats could prohibit drilling in certain areas or require the implementation of expensive mitigation or conservation measures. The designation of previously unprotected species in areas where we operate as threatened or 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 a material adverse impact on our ability to develop and produce our reserves.
The enactment of derivatives legislation could have an adverse effect on our ability to use derivative instruments to reduce the effect of commodity price, interest rate and other risks associated with our business.
The Dodd-Frank Act, enacted on July 21, 2010, established federal oversight and regulation of the over-the-counter derivatives market and of entities, such as us, that participate in that market. The Dodd-Frank Act requires the CFTC and the SEC to promulgate rules and regulations implementing the Dodd-Frank Act. In December 2016, the CFTC re-proposed regulations implementing limits on positions in certain core futures and equivalent swaps contracts for or linked to certain physical commodities, subject to exceptions for certain bona fide hedging transactions. The Dodd-Frank Act and CFTC rules also will require us, in connection with certain derivatives activities, to comply with clearing and trade-execution requirements (or to take steps to qualify for an exemption to such requirements). In addition, the CFTC and certain banking regulators have adopted final rules establishing minimum margin requirements for uncleared swaps. Although we expect to qualify for the end-user exception to the mandatory clearing, trade-execution and margin requirements for swaps entered to hedge our commercial risks, the application of such requirements to other market participants, such as swap dealers, may change the cost and availability of the swaps that we use for hedging. In addition, if any of our swaps do not qualify for the commercial end-user exception, posting of collateral could impact liquidity and reduce cash available to us for capital expenditures, therefore reducing our ability to execute hedges to reduce risk and protect cash flow. It is not possible at this time to predict with certainty the full effects of the Dodd-Frank Act and CFTC rules on us or the timing of such effects. The Dodd-Frank Act and any new regulations could significantly increase the cost of derivative contracts, materially alter the terms of derivative contracts, reduce the availability of derivatives to protect against risks we encounter, and reduce our ability to monetize or restructure our existing derivative contracts. If we reduce our use of derivatives as a result of the Dodd-Frank Act and CFTC rules, our results of operations may become more volatile and our cash flows may be less predictable, which could adversely affect our ability to plan for and fund capital expenditures. Finally, the Dodd-Frank Act was intended, in part, to reduce the volatility of oil, natural gas and NGL prices, which some legislators attributed to speculative trading in derivatives and commodity instruments related to oil, natural gas and NGLs. Our revenues could therefore be adversely affected if a consequence of the Dodd-Frank Act and CFTC rules is to lower commodity prices. Any of these consequences could have a material and adverse effect on us, our financial condition or our results of operations.
Future federal, state or local legislation also may impose new or increased taxes or fees on oil and natural gas extraction or production.
Future changes in U.S. federal income tax laws, or the introduction of a carbon tax, as well as any similar changes in state law, could eliminate or postpone certain tax deductions that currently are available with respect to oil and natural gas development, or increase costs, and any such changes could have an adverse effect on our financial position, results of operations, and cash flows. Additionally, future legislation could be enacted that increases the taxes or fees imposed on oil and
natural gas extraction or production. Any such legislation could result in increased operating costs and/or reduced consumer demand for petroleum products, which in turn could affect the prices we receive for our oil, natural gas or NGLs.
Anti-indemnity provisions enacted by many states may restrict or prohibit a party’s indemnification of us.
We typically enter into agreements with our customers governing the use and operation of our systems, which usually include certain indemnification provisions for losses resulting from operations. Such agreements may require each party to indemnify the other against certain claims regardless of the negligence or other fault of the indemnified party; however, many states place limitations on contractual indemnity agreements, particularly agreements that indemnify a party against the consequences of its own negligence. Furthermore, certain states, including Louisiana, New Mexico, Texas and Wyoming have enacted statutes generally referred to as “oilfield anti-indemnity acts” expressly prohibiting certain indemnity agreements contained in or related to oilfield services agreements. Such anti-indemnity acts may restrict or void a party’s indemnification of us, which could have a material adverse effect on our business, financial condition, prospects and results of operations.
Our effective tax rate may change in the future, which could adversely impact us.
The TCJA significantly changed the U.S. federal income taxation of U.S. corporations, including by reducing the U.S. corporate income tax rate, limiting interest deductions and certain deductions for executive compensation, permitting immediate expensing of certain capital expenditures, and revising the rules governing net operating losses. The TCJA remains unclear in some respects and continues to be subject to potential amendments and technical corrections. The United States Treasury Department and the IRS have issued significant guidance since the TCJA was enacted, interpreting the TCJA and clarifying some of the uncertainties, and are continuing to issue new guidance. There are still significant aspects of the TCJA for which further guidance is expected, and both the timing and contents of any such future guidance are uncertain.
Further, changes to the U.S. federal income tax laws are proposed regularly and there can be no assurance that, if enacted, any such changes would not have an adverse impact on us. For example, President Biden has suggested the reversal or modification of some portions of the TCJA and certain of these proposals, if enacted, could increase our effective tax rate. There can be no assurance that any such proposed changes will be introduced as legislation or, if introduced, later enacted, and, if enacted, what form such enacted legislation would take. Such changes could potentially have retroactive effect.
In light of these factors, there can be no assurance that our effective income tax rate will not change in future periods. If the effective tax rate were to increase as a result of the future legislation, our business could be adversely affected.
Risks Related to Our Common Stock
The market price of our common stock may be volatile, which could cause the value of your investment to decline.
The stock markets have experienced extreme volatility that has often been unrelated to the operating performance of particular companies. These broad market fluctuations may adversely affect the trading price of our common stock. The market price of our common stock may also fluctuate significantly in response to the following factors, some of which are beyond our control:
•our operating and financial performance and drilling locations, including reserve estimates;
•actual or anticipated fluctuations in our quarterly results of operations, and financial indicators, such as net income, cash flow and revenues;
•our failure to meet revenue, reserves or earnings estimates by research analysts or other investors;
•sales of our common stock by the Company or other stockholders, or the perception that such sales may occur;
•the public reaction to our press releases, other public announcements, and filings with the SEC;
•strategic actions by our competitors or competition for, among other things, capital, acquisition of reserves, undeveloped land and skilled personnel;
•publication of research reports about us or the oil and natural gas exploration and production industry generally;
•changes in revenue or earnings estimates, or changes in recommendations or withdrawal of research coverage, by equity research analysts;
•speculation in the press or investment community;
•the failure of research analysts to cover our common stock;
•increases in market interest rates or funding rates, which may increase our cost of capital;
•changes in market valuations of similar companies;
•changes in accounting principles, policies, guidance, interpretations or standards;
•additions or departures of key management personnel;
•actions by our stockholders;
•commencement or involvement in litigation;
•general market conditions, including fluctuations in commodity prices;
•political conditions in oil and natural gas producing regions;
•domestic and international economic, legal and regulatory factors unrelated to our performance; and
•the realization of any risks described under this “Risk Factors” section.
Moreover, the stock markets in general have experienced substantial volatility that has often been unrelated to the operating performance of individual companies. These broad market fluctuations may also adversely affect the trading price of our common stock.
In the past, following periods of volatility in the market price of a company’s securities, stockholders have often instituted class action securities litigation against those companies. Such litigation, if instituted, could result in substantial costs and diversion of management attention and resources, which could significantly harm our business, financial condition, results of operations and reputation.
Future sales or the possibility of future sales of a substantial amount of our common stock may depress the price of shares of our common stock.
Future sales or the availability for sale of substantial amounts of our common stock in the public market could adversely affect the prevailing market price of our common stock and could impair our ability to raise capital through future sales of equity securities.
We may issue shares of our common stock or other securities from time to time as consideration for future acquisitions and investments. If any such acquisition or investment is significant, the number of shares of our common stock, or the number or aggregate principal amount, as the case may be, of other securities that we may issue may in turn be substantial. We may also grant registration rights covering those shares of our common stock or other securities in connection with any such acquisitions and investments.
We cannot predict the size of future issuances of our common stock or the effect, if any, that future issuances and sales of our common stock will have on the market price of our common stock. Sales of substantial amounts of our common stock (including shares of our common stock issued in connection with an acquisition), or the perception that such sales could occur, may adversely affect prevailing market prices for our common stock.
If we fail to continue to meet the requirements for continued listing on the NYSE American stock exchange, our common stock could be delisted from trading, which would decrease the liquidity of our common stock and ability to raise additional capital.
Our common stock is listed for quotation on the NYSE American and we are required to meet specified financial requirements, including requirements for a minimum amount of capital, a minimum price per share, a minimum public float, and continued business operations so that we are not delisted or characterized as a “public shell company.” If we are unable to comply with the NYSE American stock exchange’s listing standards, NYSE may determine to delist our common stock from the NYSE American stock exchange or other of NYSE’s trading markets. If our common stock is delisted for any reason, it could reduce the value of our common stock and liquidity.
If securities analysts do not publish research or reports about our business or if they publish negative evaluations of our stock, the price of our stock could decline.
The trading market for our common stock relies, in part, on the research and reports that industry or financial analysts publish about us or our business. Equity research analysts may elect not to provide research coverage of our common stock, and such lack of research coverage may adversely affect the market price of our common stock. In the event we do have equity research analyst coverage, we will not have any control over the analysts or the content and opinions included in their reports. The price of our common stock could decline if one or more equity research analysts downgrade our stock or issue other unfavorable commentary or research. If one or more equity research analysts ceases coverage of us or fails to publish reports on us regularly, demand for our common stock could decrease, which in turn could cause our stock price or trading volume to decline.
We may not generate sufficient cash to support any dividend to our common stockholders.
The amount of any dividend will depend on the amount of cash we generate from operations, which will fluctuate from quarter to quarter based on, among other things:
•the volumes of crude oil, natural gas and NGLs that we produce;
•market prices of crude oil, natural gas and NGLs and their effect on our drilling and development plan;
•the levels of our operating expenses, maintenance expenses and general and administrative expenses;
•regulatory action affecting:
•the supply of, or demand for, crude oil, natural gas and NGLs;
•our operating costs or our operating flexibility;
•prevailing economic conditions; and
•adverse weather conditions.
In addition, the actual amount of cash we will have available for dividends will depend on other factors, some of which are beyond our control, including:
•our debt service requirements and other liabilities;
•our ability to borrow under our debt agreements to fund our capital expenditures and operating expenditures and to pay dividends;
•fluctuations in our working capital needs;
•restrictions on dividends contained in any of our debt agreements;
•the cost of acquisitions, if any; and
•other business risks affecting our cash levels.
Our quarterly cash dividends, if any, may vary significantly both quarterly and annually.
Investors who are looking for an investment that will pay regular and predictable quarterly dividends should not invest in our common stock. Our business performance may be more volatile, and our cash flow may be less stable, than other business models that pay dividends. The amount of our quarterly dividends will generally depend on the performance of our business, which has a limited operating history.
The Board may modify or revoke our dividend policy at any time at its discretion.
We are not required to pay any dividends on our common stock at all. Accordingly, the Board may change our dividend policy at any time at its discretion and could elect not to pay dividends on our common stock for one or more quarters. Any modification or revocation of our cash dividend policy could substantially reduce or eliminate the amounts of dividends to our common stockholders. The amount of dividends we make, if any, and the decision to make any dividend at all will be determined by our Board, whose interests may differ from those of our common stockholders.
The amount of cash we have available for dividends to our common stockholders depends primarily on our cash flow and not solely on our profitability, which may prevent us from paying dividends, even during periods in which we record net income.
The amount of cash we have available for dividends depends primarily upon our cash flow and not solely on our profitability, which will be affected by non-cash items. As a result, we may pay cash dividends during periods when we record a net loss for financial accounting purposes and, conversely, we might fail to pay cash dividends on our common stock during periods when we record net income for financial accounting purposes.
Delaware law imposes restrictions on our ability to pay cash dividends on our common stock.
Our common stockholders do not have a right to dividends on such shares unless declared or set aside for payment by our Board. Under Delaware law, cash dividends on capital stock may only be paid from “surplus” or, if there is no “surplus,” from the corporation’s net profits for the then-current or the preceding fiscal year. Unless we operate profitably, our ability to pay dividends on our common stock would require the availability of adequate “surplus,” which is defined as the excess, if any, of net assets (total assets less total liabilities) over capital. Our business may not generate sufficient surplus or net profits from operations to enable us to pay dividends on our common stock.
We may issue preferred stock whose terms could adversely affect the voting power or value of our common stock.
Our certificate of incorporation authorizes us to issue, without the approval of our shareholders, one or more classes or series of preferred stock having such designations, preferences, limitations and relative rights, including preferences over our common stock respecting dividends and distributions, as our Board may determine. The terms of one or more classes or series of preferred stock could adversely impact the voting power or value of our common stock. For example, we might grant holders of preferred stock the right to elect some number of our directors in all events or on the happening of specified events or the right to veto specified transactions. Similarly, the repurchase or redemption rights or liquidation preferences we might assign to holders of preferred stock could affect the residual value of the common stock.
Risks Related to the Company
If we fail to maintain an effective system of internal control over financial reporting, we may not be able to accurately report our financial results or prevent fraud. As a result, stockholders could lose confidence in our financial and other public reporting, which would harm our business and the trading price of our common stock.
Effective internal control over financial reporting is necessary for us to provide reliable financial reports and, together with adequate disclosure controls and procedures, is designed to prevent fraud. Any failure to implement required new or improved controls, or difficulties encountered in their implementation, could cause us to fail to meet our reporting obligations. In addition, any testing, as and when required, conducted in connection with Section 404 of the Sarbanes-Oxley Act, or Section 404, or any subsequent testing by our independent registered public accounting firm, as and when required, may reveal deficiencies in our internal control over financial reporting that are deemed to be significant deficiencies or material weaknesses or that may require prospective or retroactive changes to our financial statements or identify other areas for further attention or improvement. Inferior internal controls could also cause investors to lose confidence in our reported financial information, which could have a negative effect on the trading price of our common stock.
We are a smaller reporting company and we cannot be certain if the reduced disclosure requirements applicable to smaller reporting companies will make our common stock less attractive to investors.
We are currently a “smaller reporting company” as defined by Rule 12b-2 of the Exchange Act. As a “smaller reporting company,” we are subject to reduced disclosure obligations in our SEC filings compared to other issuers, including, among other things, an exemption from the requirement to present five years of selected financial data, being required to provide only two years of audited financial statements in annual reports and being subject to simplified executive compensation disclosures. Until such time as we cease to be a “smaller reporting company,” such reduced disclosure in our SEC filings may make it harder for investors to analyze our operating results and financial prospects. If some investors find our common stock less attractive as a result of any choices to reduce disclosure we may make, there may be a less active trading market for our common stock and our stock price may be more volatile.
Our business and operations could be adversely affected if we lose key personnel.
We depend to a large extent on the services of our officers, including Bobby Riley, our Chief Executive Officer, Kevin Riley, our President, Philip Riley, our Chief Financial Officer, Corey Riley, our Executive Vice President – Business Intelligence, Michael Palmer, our Executive Vice President Corporate – Land. These individuals have extensive experience and expertise in evaluating and analyzing producing oil and natural gas properties and drilling prospects, maximizing production from oil and natural gas properties and developing and executing financing strategies. The loss of any of these individuals could have a material adverse effect on our operations. We do not maintain key-man life insurance with respect to any management personnel. Our success will be dependent on our ability to continue to retain and utilize skilled technical personnel. The loss of the services of our senior management or technical personnel could have a material adverse effect on our business, financial condition, and results of operations.
Our executive officers, directors and principal stockholders have the ability to control or significantly influence all matters submitted to the Company’s stockholders for approval.
As of December 31, 2022, our executive officers, directors and principal stockholders, in the aggregate, own 77.3% of the fully diluted common stock of the Company. As a result, if these stockholders were to choose to act together, they would be able to control or significantly influence all matters submitted to the Company’s stockholders for approval, as well as the Company’s management and affairs. For example, these persons, if they choose to act together, would control or significantly influence the election of directors and approval of any merger, consolidation or sale of all or substantially all of the Company’s
assets. This concentration of voting power could delay or prevent an acquisition of the Company on terms that other stockholders may desire.
Provisions in our corporate charter documents and under Delaware law could make an acquisition of the Company, which may be beneficial to our stockholders, more difficult and may prevent attempts by our stockholders to replace or remove current management.
Provisions in our corporate charter and by-laws may discourage, delay or prevent a merger, acquisition or other changes in control that stockholders may consider favorable, including transactions in which stockholders might otherwise receive a premium for their shares. These provisions also could limit the price that investors might be willing to pay in the future for shares of our common stock, thereby depressing the market price of our common stock. In addition, because our Board is responsible for appointing the members of the management team, these provisions may frustrate or prevent any attempts by our stockholders to replace or remove current management by making it more difficult for stockholders to replace members of our board of directors. Among other things, these provisions:
•allow the authorized number of directors to be changed only by resolution of the Board;
•after a certain date, limit the manner in which stockholders can remove directors from the Board;
•establish advance notice requirements for stockholder proposals that can be acted on at stockholder meetings and nominations to the Board;
•after a certain date, require that stockholder actions must be effected at a duly called stockholder meeting and prohibit actions by written consent;
•limit who may call stockholder meetings;
•authorize the Board to issue preferred stock without stockholder approval, which could be used to institute a shareholder rights plan, or so-called “poison pill,” that would work to dilute the stock ownership of a potential hostile acquirer, effectively preventing acquisitions that have not been approved by the Board; and
•after a certain date, require the approval of the holders of at least 66 2/3% of the votes that all the stockholders would be entitled to cast to amend or repeal certain provisions of our charter or bylaws.
Our bylaws provide that the Court of Chancery of the State of Delaware will be the exclusive forum for substantially all disputes between the Company and its stockholders, which could limit stockholders’ ability to obtain a favorable judicial forum for disputes with the Company or its directors, officers, employees or stockholders.
Our bylaws provide that, unless the Company consents in writing to the selection of an alternative forum, the Court of Chancery of the State of Delaware is the exclusive forum for any derivative action or proceeding brought on the Company’s behalf, any action asserting a breach of fiduciary duty owed by Company’s directors, officers, other employees or stockholders to the Company or its stockholders, any action asserting a claim against the Company arising pursuant to the Delaware General Corporation Law or as to which the Delaware General Corporation Law confers jurisdiction on the Court of Chancery of the State of Delaware, or any action asserting a claim arising pursuant to the Company’s certificate of incorporation or bylaws or governed by the internal affairs doctrine.
Our bylaws provide that, unless the Company consents in writing to the selection of an alternative forum, the federal district courts of the United States of America shall, to the fullest extent permitted by law, be the sole and exclusive forum for any actions arising under the Securities Act of 1933, as amended, or the Securities Exchange Act of 1934, as amended.
These provisions may limit a stockholder’s ability to bring a claim in a judicial forum that it finds favorable for disputes with the Company or its directors, officers, employees or stockholders, which may discourage such lawsuits against the Company and its directors, officers, employees or stockholders. Alternatively, if a court were to find these provisions in our bylaws to be inapplicable or unenforceable in an action, the Company may incur additional costs associated with resolving such action in other jurisdictions, which could adversely affect our business and financial condition.
Conflicts of interest could arise in the future between us, on the one hand, and certain of our stockholders and their respective affiliates, including their funds and their respective portfolio companies, on the other hand, concerning among other things, potential competitive business activities or business opportunities.
Investment funds managed by certain of our stockholders are in the business of making investments in entities in the U.S. energy industry. As a result, certain of our stockholders 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 customers. Certain of our stockholders and their respective portfolio companies 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. Under our certificate of incorporation, certain of our stockholders and/or one or more of their respective affiliates are permitted to engage in business activities or invest in or acquire businesses which may compete with our business or do business with any client of ours. Any actual or perceived conflicts of interest with respect to the foregoing could have an adverse impact on the trading price of our common stock.