PNRG 10-Q
Primeenergy Resources Corp (PNRG)
Table of Contents
QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
(State or other jurisdiction of incorporation or organization) |
(I.R.S. employer Identification No.) |
Title of each class |
Trading Symbol(s) |
Name of each exchange on which registered | ||
| Large Accelerated Filer | ☐ | Accelerated Filer | ☐ | |||
Non-Accelerated Filer |
☒ | Smaller Reporting Company | ||||
| Emerging growth company | ||||||
Table of Contents
PrimeEnergy Resources Corporation
Index to Form 10-Q
September 30, 2023
Table of Contents
Definitions of Certain Terms and Conventions Used Herein
Within this Report, the following terms and conventions have specific meanings:
Measurements.
| • | “Bbl” means a standard barrel containing 42 United States gallons. |
| • | “BOE” means a barrel of oil equivalent and is a standard convention used to express oil and gas volumes on a comparable oil equivalent basis. Gas equivalents are determined under the relative energy content method by using the ratio of six thousand cubic feet of gas to one Bbl of oil or natural gas liquid. |
| • | “BOEPD” means BOE per day. |
| • | “Btu” means British thermal unit, which is a measure of the amount of energy required to raise the temperature of one pound of water one degree Fahrenheit. |
| • | “MBbl” means one thousand Bbls. |
| • | “MBOE” means one thousand BOEs. |
| • | “Mcf” means one thousand cubic feet and is a measure of gas volume. |
| • | “MMcf” means one million cubic feet. |
Indices.
| • | “Brent” means Brent oil price, a major trading classification of light sweet oil that serves as a benchmark price for oil worldwide. |
| • | “WAHA” is a benchmark pricing hub for West Texas gas. |
| • | “WTI” means West Texas Intermediate, a light sweet blend of oil produced from fields in western Texas and is a grade of oil used as a benchmark in oil pricing. General terms and conventions. |
| • | “DD&A” means depletion, depreciation and amortization. |
| • | “ESG” means environmental, social and governance. |
| • | “GAAP” means accounting principles generally accepted in the United States of America. |
| • | “GHG” means greenhouse gases. |
| • | “LNG” means liquefied natural gas. |
| • | “NGLs” means natural gas liquids, which are the heavier hydrocarbon liquids that are separated from the gas stream; such liquids include ethane, propane, isobutane, normal butane and natural gasoline. |
| • | “NYMEX” means the New York Mercantile Exchange. |
| • | “OPEC” means the Organization of Petroleum Exporting Countries. |
| • | “PrimeEnergy” or the “Company” means PrimeEnergy Resources Corporation and its subsidiaries. |
| • | “Proved developed reserves” means reserves that can be expected to be recovered through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well. |
| • | “Proved reserves” means those quantities of oil and gas, which, by analysis of geosciences and engineering data, can be estimated with reasonable certainty to be economically producible – from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations – prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time. |
| (i) | The area of the reservoir considered as proved includes: (A) The area identified by drilling and limited by fluid contacts, if any, and (B) Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data. |
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Table of Contents
| (ii) | In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons as seen in a well penetration unless geoscience, engineering or performance data and reliable technology establishes a lower contact with reasonable certainty. |
| (iii) | Where direct observation from well penetrations has defined a highest known oil elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering or performance data and reliable technology establish the higher contact with reasonable certainty. |
| (iv) | Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when: (A) Successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and (B) The project has been approved for development by all necessary parties and entities, including governmental entities. |
| (v) | Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions. |
| • | “Proved undeveloped reserves” means reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. |
| (i) | Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances. |
| (ii) | Undrilled locations can be classified as having proved undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances, justify a longer time. |
| (iii) | Under no circumstances shall estimates for proved undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, or by other evidence using reliable technology establishing reasonable certainty. |
| • | “SEC” means the United States Securities and Exchange Commission. |
| • | “Standardized Measure” means the after-tax present value of estimated future net cash flows of proved reserves, determined in accordance with the rules and regulations of the SEC, using prices and costs employed in the determination of proved reserves and a 10 percent discount rate. |
| • | “U.S.” means United States. |
| • | With respect to information on the working interest in wells, drilling locations and acreage, “net” wells, drilling locations and acres are determined by multiplying “gross” wells, drilling locations and acres by the Company’s working interest in such wells, drilling locations or acres. Unless otherwise specified, wells, drilling locations and acreage statistics quoted herein represent gross wells, drilling locations or acres. |
| • | “WASP” means weighted average sales price. |
| • | All currency amounts are expressed in U.S. dollars. |
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Table of Contents
CAUTIONARY STATEMENT CONCERNING FORWARD-LOOKING STATEMENTS
This information in this Quarterly Report on Form 10-Q (this “Report”) contains forward-looking statements that involve risks and uncertainties. When used in this document, the words “believes,” “plans,” “expects,” “anticipates,” “forecasts,” “models,” “intends,” “continue,” “may,” “will,” “could,” “should,” “future,” “potential,” “estimate,” or the negative of such terms and similar expressions as they relate to the Company are intended to identify forward-looking statements, which are generally not historical in nature. The forward-looking statements are based on the Company’s current expectations, assumptions, estimates and projections about the Company and the industry in which the Company operates. Although the Company believes that the expectations and assumptions reflected in the forward-looking statements are reasonable as and when made, they involve risks and uncertainties that are difficult to predict and, in many cases, beyond the Company’s control. In addition, the Company may be subject to currently unforeseen risks that may have a materially adverse effect on it.
These risks and uncertainties include, among other things, volatility of commodity prices; product supply and demand; the impact of armed conflict (including the war in Ukraine) and related political instability on economic activity and oil and gas supply and demand; competition; the ability to obtain drilling, environmental and other permits and the timing thereof; the effect of future regulatory or legislative actions on PrimeEnergy or the industry in which it operates, including potential changes to tax laws; the ability to obtain approvals from third parties and negotiate agreements with third parties on mutually acceptable terms; potential liability resulting from pending or future litigation; the costs, including the potential impact of cost increases due to inflation and supply chain disruptions, and results of development and operating activities; the impact of a widespread outbreak of an illness, such as the COVID19 pandemic, on global and U.S. economic activity, oil and gas demand, and global and U.S. supply chains; the risk of new restrictions with respect to development activities, including potential changes to regulations resulting in limitations on the Company’s ability to dispose of produced water; availability of equipment, services, resources and personnel required to perform the Company’s development and operating activities; access to and availability of transportation, processing, fractionation, refining, storage and export facilities; PrimeEnergy’s ability to replace reserves, implement its business plans or complete its development activities as scheduled; the Company’s ability to achieve its emissions reductions, flaring and other ESG goals; access to and cost of capital; the financial strength of (i) counterparties to PrimeEnergy’s credit facility and derivative contracts, (ii) issuers of PrimeEnergy’s investment securities and (iii) purchasers of PrimeEnergy’s oil, NGL and gas production and downstream sales of purchased commodities; uncertainties about estimates of reserves, identification of drilling locations and the ability to add proved reserves in the future; the assumptions underlying forecasts, including forecasts of production, operating cash flow, well costs, capital expenditures, rates of return, expenses, and cash flow from downstream purchases and sales of oil and gas, net of firm transportation commitments; tax rates; quality of technical data; environmental and weather risks, including the possible impacts of climate change on the Company’s operations and demand for its products; cybersecurity risks; the risks associated with the ownership and operation of the Company’s water services business and acts of war or terrorism. In addition, the Company may be subject to currently unforeseen risks that may have a materially adverse effect on it.
Accordingly, no assurances can be given that the actual events and results will not be materially different than the anticipated results described in the forward-looking statements. See “Part I, Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations,” “Part 1, Item 3. Quantitative and Qualitative Disclosures About Market Risk” and “Part II, Item 1A. Risk Factors” in this Report and “Part I, Item 1. Business — Competition,” “Part I, Item 1. Business —Regulation,” “Part I, Item 1A. Risk Factors,” “Part II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” and “Part II, Item 7A. Quantitative and Qualitative Disclosures About Market Risk” in the Company’s Annual Report on Form 10-K for the year ended December 31, 2022 for a description of various factors that could materially affect the ability of to achieve the anticipated results described in the forward-looking statements. Readers are cautioned not to place undue reliance on forward-looking statements, which speak only as of the date hereof. PrimeEnergy undertakes no duty to publicly update these statements except as required by law.
3
Table of Contents
Item 1. |
FINANCIAL STATEMENTS |
September 30, 2023 (Unaudited) |
December 31, 2022 |
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ASSETS |
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Current assets: |
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Cash and cash equivalents |
$ | $ | ||||||
Accounts receivable, net |
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Prepaid obligations |
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Due from related parties |
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Derivative asset |
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Other current assets |
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Total current assets |
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Properties and equipment: |
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Proved oil and gas properties, using the successful efforts method of accounting |
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Other property |
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Accumulated depletion and depreciation |
( |
) | ( |
) | ||||
Total properties, net |
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Right-of-use |
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Other assets |
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Total Assets |
$ | $ | ||||||
LIABILITIES AND EQUITY |
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Current liabilities: |
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Accounts payable |
$ | $ | ||||||
Accrued liabilities |
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Current portion of asset retirement and other long-term obligations |
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Due to related parties |
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Derivative liability |
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Total current liabilities |
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Long-term bank debt |
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Asset retirement obligations |
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Deferred income taxes |
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Other long-term obligations |
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Total Liabilities |
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COMMITMENTS AND CONTINGENCIES |
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Equity: |
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Common stock, $ |
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Additional paid in capital |
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Retained earnings |
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Treasury stock, at cost; |
( |
) | ( |
) | ||||
Total Equity |
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Total Liabilities and Equity |
$ | $ | ||||||
Three Months Ended September 30, |
Nine Months Ended September 30, |
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2023 |
2022 |
2023 |
2022 |
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| Revenues: |
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| Oil |
$ | $ | $ | $ | ||||||||||||
| Natural gas |
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| Natural gas liquids |
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| Field service |
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| Realized loss on derivative instruments, net |
( |
) | ( |
) | ( |
) | ||||||||||
| Unrealized gain on derivative instruments, net |
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| Other income |
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| Total revenues |
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| Costs and expenses: |
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| Oil and gas production |
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| Production and ad valorem taxes |
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| Field service |
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| Depreciation, depletion and amortization |
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| Accretion of discount on asset retirement obligations |
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| General and administrative |
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| Total costs and expenses |
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| Gain on sale and exchange of assets |
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| Income from operations |
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| Other income (expense) |
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| Interest expense |
( |
) | ( |
) | ( |
) | ( |
) | ||||||||
| Interest income |
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| |
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| Income before income taxes |
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| Income tax provision |
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| Net income |
$ | $ | $ | $ | ||||||||||||
| |
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| Net income per share attributable to common stockholders: |
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| Basic |
$ | $ | $ | $ | ||||||||||||
| Diluted |
$ | $ | $ | $ | ||||||||||||
| Weighted average shares outstanding: |
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| Basic |
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| Diluted |
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Common Stock |
Additional Paid-In Capital |
Retained Earnings |
Treasury Stock |
Total Equity |
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Shares Outstanding |
Common Stock |
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Balance at December 31, 2022 |
$ | $ | $ | $ | ( |
) | $ | |||||||||||||||||
Purchase of treasury stock |
( |
) | — | — | — | ( |
) | ( |
) | |||||||||||||||
Net income |
— | — | — | — | ||||||||||||||||||||
Balance at March 31, 2023 |
$ | $ | $ | $ | ( |
) | $ | |||||||||||||||||
Purchase of treasury stock |
( |
) | — | — | — | ( |
) | ( |
) | |||||||||||||||
Net income |
— | — | — | — | ||||||||||||||||||||
Balance at June 30, 2023 |
$ | $ | $ | $ | ( |
) | $ | |||||||||||||||||
Purchase of treasury stock |
( |
) | — | — | — | ( |
) | ( |
) | |||||||||||||||
Net income |
— | — | — | — | ||||||||||||||||||||
Balance at September 30, 2023 |
$ | $ | $ | $ | ( |
) | $ | |||||||||||||||||
Common Stock |
Additional Paid-In Capital |
Retained Earnings |
Treasury Stock |
Total Equity |
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Shares Outstanding |
Common Stock |
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Balance at December 31, 2021 |
$ | $ | $ | $ | ( |
) | $ | |||||||||||||||||
Purchase of treasury stock |
( |
) | ( |
) | ||||||||||||||||||||
Net income |
— | — | — | — | ||||||||||||||||||||
Balance at March 31, 2022 |
$ | $ | $ | $ | ( |
) | $ | |||||||||||||||||
Purchase of treasury stock |
( |
) | — | — | — | ( |
) | ( |
) | |||||||||||||||
Net income |
— | — | — | — | ||||||||||||||||||||
Balance at June 30, 2022 |
$ | $ | $ | $ | ( |
) | $ | |||||||||||||||||
Purchase of treasury stock |
( |
) | — | — | — | ( |
) | ( |
) | |||||||||||||||
Net income |
— | — | — | — | ||||||||||||||||||||
Balance at September 30, 2022 |
$ | $ | $ | $ | ( |
) | $ | |||||||||||||||||
2023 |
2022 |
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Cash Flows from Operating Activities: |
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Net Income |
$ | $ | ||||||
Adjustments to reconcile net income to net cash provided by operating activities: |
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Depreciation, depletion, and amortization |
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Gain on sale and exchange of assets |
( |
) | ( |
) | ||||
Accretion of discount on asset retirement obligations |
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Unrealized gain on derivative instruments, net |
( |
) | ( |
) | ||||
Deferred income taxes |
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Changes in assets and liabilities: |
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Accounts receivable |
( |
) | ( |
) | ||||
Due from related parties |
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Due to related parties |
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Prepaids obligations |
( |
) | ||||||
Accounts payable |
( |
) | ||||||
Accrued liabilities |
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Other, net |
( |
) | ||||||
Net Cash Provided by Operating Activities |
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Cash Flows from Investing Activities: |
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Capital expenditures, including exploration expense |
( |
) | ( |
) | ||||
Proceeds from sale of properties and equipment |
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Net Cash Provided by (Used in) Investing Activities |
( |
) | ||||||
Cash Flows from Financing Activities: |
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Purchase of stock for treasury |
( |
) | ( |
) | ||||
Repayment of long-term bank debt and other long-term obligations |
( |
) | ( |
) | ||||
Net Cash Used in Financing Activities |
( |
) | ( |
) | ||||
Net (Decrease) Increase in Cash and Cash Equivalents |
( |
) | ||||||
Cash and Cash Equivalents at the Beginning of the Period |
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Cash and Cash Equivalents at the End of the Period |
$ | $ | ||||||
Supplemental Disclosures: |
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Income taxes paid |
$ | $ | ||||||
Interest paid |
$ | $ | ||||||
(Thousands of dollars) |
September 30, 2023 |
December 31, 2022 |
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Accounts Receivable: |
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Joint interest billing |
$ | $ | ||||||
Trade receivables |
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Oil and gas sales |
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Other |
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(Thousands of dollars) |
September 30, 2023 |
December 31, 2022 |
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Less: Allowance for doubtful accounts |
( |
) | ( |
) | ||||
Total |
$ | $ | ||||||
Accounts Payable: |
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Trade |
$ | $ | ||||||
Royalty and other owners |
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Partner advances |
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Other |
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Total |
$ | $ | ||||||
(Thousands of dollars) |
September 30, 2023 |
December 31, 2022 |
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Accrued Liabilities: |
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Compensation and related expenses |
$ | $ | ||||||
Property costs |
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Taxes |
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Operating costs |
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Other |
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Total |
$ | $ | ||||||
(Thousands of dollars) |
Operating Leases |
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2023 |
$ | |||
2024 |
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2025 |
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Total undiscounted lease payments |
$ | |||
Less: Amount associated with discounting |
( |
) | ||
Total net |
$ | |||
Less: Current portion included in current portion of asset retirement and other long-term obligations |
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Non-current portion included in other long-term obligations |
$ | |||
(Thousands of dollars) |
September 30, 2023 |
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Asset retirement obligation at December 31, 2022 |
$ | |||
Additions |
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Dispositions |
( |
) | ||
Liabilities settled |
( |
) | ||
Accretion of discount |
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Asset retirement obligation at September 30, 2023 |
$ | |||
Less current portion of asset retirement obligations |
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Asset retirement obligations, long-term |
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September 30, 2023 |
Quoted Prices in Active Markets For Identical Assets (Level 1) |
Significant Other Observable Inputs (Level 2) |
Significant Unobservable Inputs (Level 3) |
Balance at September 30, 2023 |
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(Thousands of dollars) |
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Assets |
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Commodity derivative contracts |
$ | — | $ | — | $ | $ | ||||||||||
Total assets |
$ | — | $ | — | $ | $ | ||||||||||
Liabilities |
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Commodity derivative contracts |
$ | — | $ | — | $ | $ | ||||||||||
Total liabilities |
$ | — | $ | — | $ | $ | ||||||||||
December 31, 2022 |
Quoted Prices in Active Markets For Identical Assets (Level 1) |
Significant Other Observable Inputs (Level 2) |
Significant Unobservable Inputs (Level 3) |
Balance at December 31, 2022 |
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(Thousands of dollars) |
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Assets |
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Commodity derivative contracts |
$ | — | $ | — | $ | $ | ||||||||||
Total assets |
$ | — | $ | — | $ | $ | ||||||||||
Liabilities |
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Commodity derivative contracts |
$ | — | $ | — | $ | ( |
) | $ | ( |
) | ||||||
Total liabilities |
$ | — | $ | — | $ | ( |
) | $ | ( |
) | ||||||
| (Thousands of dollars) |
||||
| Net Liabilities – December 31, 2022 |
$ | ( |
) | |
| Total realized and unrealized gains (losses): |
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| in earnings (a) |
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| Purchases, sales, issuances and settlements |
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| |
|
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| Net Liabilities — September 30, 2023 |
$ | |||
| |
|
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| (a) | Derivative instruments are reported in revenues as realized gain/loss and on a separately reported line item captioned unrealized gain/loss on derivative instruments. |
Fair Value |
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(Thousands of dollars) |
Balance Sheet Location |
September 30, 2023 |
December 31, 2022 |
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| Asset Derivatives: |
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| Derivatives not designated as cash-flow hedging instruments: |
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| Crude oil commodity contract |
Derivative asset | $ | $ | |||||||||
| Natural gas commodity contract |
Derivative asset | |||||||||||
| |
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| Total |
$ | $ | ||||||||||
| |
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|
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| Liability Derivatives: |
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| Derivatives not designated as cash-flow hedging instruments: |
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| Crude oil commodity contracts |
Derivative liability | $ | $ | ( |
) | |||||||
| Natural gas commodity contracts |
Derivative liability | ( |
) | |||||||||
| |
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| Total |
$ | $ | ( |
) | ||||||||
| |
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| Total derivative instruments |
$ | $ | ( |
) | ||||||||
| |
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Amount of gain (loss) recognized in in o me |
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| (Thousands of dollars) |
Location of gain/loss recognized in income |
2023 |
2022 |
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| Derivatives not designated as cash-flow hedge instruments: |
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| Natural gas commodity contracts |
Unrealized gain (loss) on instruments, net | ( |
) | |||||||||
| Crude oil commodity contracts |
Unrealized gain on instruments, net | |||||||||||
| Natural gas commodity contracts |
Realized gain (loss) on derivative instruments, net | ( |
) | |||||||||
| Crude oil commodity contracts |
Realized loss on derivative instruments, net | ( |
) | ( |
) | |||||||
| |
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| $ | $ | ( |
) | |||||||||
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Nine Months Ended September 30, |
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2023 |
2022 |
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Net Income (In 000’s) |
Weighted Average Number of Shares Outstanding |
Per Share Amount |
Net Loss (In 000’s) |
Weighted Average Number of Shares Outstanding |
Per Share Amount |
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| Basic |
$ | $ | $ | $ | ||||||||||||||||||||
| Effect of dilutive securities: |
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| Options (a) |
— | — | — | |||||||||||||||||||||
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| Diluted |
$ | $ | $ | $ | ||||||||||||||||||||
| |
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Three Months Ended September 30, |
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2023 |
2022 |
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Net Income (In 000’s) |
Weighted Average Number of Shares Outstanding |
Per Share Amount |
Net Loss (In 000’s) |
Weighted Average Number of Shares Outstanding |
Per Share Amount |
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| Basic |
$ | $ | $ | $ | ||||||||||||||||||||
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— | — | — | |||||||||||||||||||||
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| Diluted |
$ | $ | $ | $ | ||||||||||||||||||||
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Table of Contents
| Item 2. | MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS |
The following discussion is intended to assist you in understanding our results of operations and our present financial condition. Our Consolidated Financial Statements and the accompanying Notes to the Consolidated Financial Statements included elsewhere in this Report contain additional information that should be referred to when reviewing this material.
OVERVIEW
We are an independent oil and natural gas company engaged in acquiring, developing, and producing oil and natural gas. We own producing and non-producing properties located primarily in Texas, and Oklahoma. All of our oil and gas properties and interests are located in the United States. Assets in our principal focus areas include mature properties with long-lived reserves and significant development opportunities as well as more recently developed horizontal properties with relatively high flow rates. The Company also owns a 12.5% overriding royalty interest in over 30,000 acres in the state of West Virginia, although we are currently not receiving revenue from this asset as development has not begun. In Texas, we own well-servicing equipment that is used to service our operated properties as well as to provide oil field services to third-party operators. In addition, we own a 60-mile-long pipeline offshore on the shallow shelf of Texas that is currently idle but that we believe has future value for producers in the area. In Oklahoma, we own 649 acres of land with an estimated value of approximately $848,000, however, in November of this year have agreed to sell 136 acres for $306,000. Also, in Prattville, Alabama, we hold a 33.3% interest in a limited partnership that owns a 138,000-square-foot retail shopping center on ten acres. There is currently no debt on the shopping center and it has approximately $500,000 of working capital on its balance sheet. We believe our portfolio of oil and gas assets positions us well for both the current commodity price environment and future potential upside as we develop our attractive resource opportunities. Our primary sources of liquidity are cash generated from operations, our credit facility, and existing cash on our balance sheet.
In addition to developing our oil and natural gas reserves, we continue to actively pursue the acquisition of producing properties. We attempt to assume the position of operator in all acquisitions of producing properties and will continue to evaluate properties for leasehold acquisition, exploration and development. To diversify and broaden our asset base, we will consider acquiring the assets or stock in other entities in the oil and gas business. Our main objective in making any such acquisitions will be to acquire income-producing assets or developable leasehold acreage to build stockholder value.
Our cash flows depend on many factors, including the price of oil and gas, the success of our acquisition and drilling activities, and the operational performance of our producing properties. On occasion, we will use derivative instruments to manage our commodity price risk. This practice may prevent us from receiving the full advantage of increases in oil and gas prices above the maximum fixed amount specified in the derivative agreements and subjects us to the credit risk of the counterparties to such agreements. When used, our derivative contracts are accounted for under mark-to-market accounting and we can expect volatility in gains and losses on contracts in our consolidated statement of operations as changes occur in the NYMEX price indices. Our most recent derivative instruments expired in March of 2023 and at this time we do not intend to enter into future derivative contracts unless required for our bank line of credit.
Our financial results depend on many factors, particularly the price of natural gas and crude oil and our ability to market our production on economically attractive terms. Commodity prices are affected by many factors outside of our control, including changes in market supply and demand, which are impacted by weather conditions, pipeline capacity constraints, inventory storage levels, basis differentials, and other factors. In addition, our realized prices are further impacted by our derivative and hedging activities when used to manage commodity price risk. As mentioned above, our most recent contracts expired in March of 2023 and we currently do not intend to use future derivative contracts unless required by our bank loan.
We derive our revenue and cash flow principally from the sale of oil, natural gas, and NGLs. As a result, our revenues are determined, to a large degree, by prevailing prices for crude oil, natural gas, and NGLs. We sell our oil and natural gas on the open market at prevailing market prices or through forward delivery contracts. Because some of our operations are located outside major markets, we are directly impacted by regional prices regardless of Henry Hub, WTI, or other major market pricing. The market price for oil, natural gas, and NGLs is dictated by supply and demand; consequently, we cannot accurately predict or control the price we may receive for our oil, natural gas, and NGLs. Index prices for oil, natural gas, and NGLs may be volatile, therefore, we cannot determine with any degree of certainty what effect increases or decreases in these prices will have on our capital program, production volumes, or revenue.
The Company is actively developing non-producing reserves of its leasehold acreage positions in Texas and Oklahoma. In the Permian Basin of West Texas, the Company maintains an acreage position of approximately 9,266 net acres, 97% of which is located in Reagan, Upton, Martin, and Midland counties of Texas where our current horizontal drilling activity is focused. In addition to the recent 22 horizontal wells completed so far in 2023 in West Texas, we believe this acreage has significant resource potential in the Spraberry, Jo Mill, and Wolfcamp reservoirs for additional drilling that could support as many as 250 additional horizontal wells. In Oklahoma, our horizontal development is focused primarily in Canadian, Kingfisher, Grady, and Garvin counties where we have approximately 4,113 net acres with additional resource potential that could support the drilling of as many as 43 new horizontal wells based on an estimate of four wells per section: two in the Mississippian and two in the Woodford Shale. Should we choose to participate with a working interest in such future development, our share of capital expenditures would be approximately $33 million at an average 10% ownership level.
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Future development plans are established based on various factors, including the expectation of available cash flows from operations and the availability of funds under our revolving credit facility.
District Information
The following table represents certain reserves and well information as of December 31, 2022.
| Gulf Coast |
Mid- Continent |
West Texas |
Other | Total | ||||||||||||||||
| Proved Reserves as of December 31, 2022 (MBoe) |
||||||||||||||||||||
| Developed |
790 | 2,549 | 7,001 | 13 | 10,353 | |||||||||||||||
| Undeveloped |
— | 110 | 6,256 | — | 6,366 | |||||||||||||||
| Total |
790 | 2,659 | 13,257 | 13 | 16,719 | |||||||||||||||
| Average Net Daily Production (Boe per day) |
227 | 897 | 3,257 | 4 | 4,385 | |||||||||||||||
| Gross Productive Wells (Working Interest and ORRI Wells) |
150 | 508 | 557 | 151 | 1,373 | |||||||||||||||
| Gross Productive Wells (Working Interest Only) |
132 | 383 | 511 | 82 | 1,108 | |||||||||||||||
| Net Productive Wells (Working Interest Only) |
69 | 169 | 254 | 6 | 498 | |||||||||||||||
| Gross Operated Productive Wells |
89 | 176 | 310 | — | 575 | |||||||||||||||
| Gross Operated Water Disposal, Injection and Supply wells |
7 | 40 | 6 | — | 53 | |||||||||||||||
In our West Texas and Gulf Coast producing regions we have field service groups that service our operated wells and provide well-site services to third-party operators. These services are performed primarily utilizing workover or swab rigs, water transport trucks, hot-oil trucks, and saltwater disposal facilities that we own and that are operated by our field employees.
Gulf Coast Region
Our production activities in the Gulf Coast region are concentrated in east and southeast Texas. This region is managed from our office in Houston, Texas. Principal producing intervals are in the Wilcox and Yegua formations at depths ranging from 5,000 to 11,000 feet. On December 31, 2022, we had 790 MBoe of proved reserves in the Gulf Coast region, which represented 4.7% of our total proved reserves. As of that date, we had 150 producing wells (69 net) in the Gulf Coast region. Focus during the past year has been on the plug and abandonment of non-performing assets and we currently operate 29 wells in the region and have a working interest in an additional 43 non-operated wells. We maintain an acreage position of over 8,707 gross (3,782 net) acres in this region, primarily in Polk County. We operate a field service group in this region from a field office in Carrizo Springs, Texas utilizing four workover rigs, water transport trucks, two commercial saltwater disposal wells, hot oil trucks, and plugging equipment. As of September 30, 2023, the Gulf Coast region has no operated wells in the process of being drilled, no waterfloods in the process of being installed, and no other related activities of material importance.
Mid-Continent Region
Our Mid-Continent activities are concentrated in central Oklahoma. This region is managed from our office in Oklahoma City, Oklahoma. As of December 31, 2022, we had 508 producing wells (169 net) in the Mid-Continent area, of which 176 wells are operated by us. Principal producing intervals are in the Robberson, Avant, Skinner, Sycamore, Bromide, McLish, Hunton, Mississippian, Oswego, Red Fork, and Chester formations at depths ranging from 1,100 to 10,500 feet. The average net daily production in our Mid-Continent Region in 2022 was 897 Boe. On December 31, 2022, we had 2,659 MBoe of proved reserves in this region, representing 16% of our total proved reserves. We currently maintain an acreage position of approximately 46,960 gross (10,137 net) acres in this region, primarily in Canadian, Kingfisher, Grant, Major, and Garvin counties. Our Mid-Continent region is actively participating with third-party operators in the horizontal development of lands that include Company owned interest in several counties in the Stack and Scoop plays of Oklahoma where drilling is primarily targeting reservoirs of the Mississippian and Woodford formations. On July 1, 2023, we divested of 38 marginally productive operated wells and one well on September 1, 2023 located in various counties of Oklahoma reducing our future plugging liability without a significant change in value of our producing reserves.
Year-to-date, in the Mid-Continent region, the Company has participated with 1.96% interest in the drilling and completion of three 3-mile-long horizontal wells in Canadian County, Oklahoma operated by Ovintiv Mid-Continent Inc. All three wells were brought on production in June of this year. The expected reserves of these three wells were included in the 2022 year-end reserve report as proved undeveloped. The Company has added additional proved-producing reserves through various over-riding royalty interests in 12 horizontal wells, totaling 5.78% net revenue interest.
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West Texas Region
Our West Texas activities are concentrated in the Permian Basin where much of the United States’ oil reserves are produced from the prolific Wolfcamp and Spraberry reservoirs. The oil is West Texas Intermediate Sweet and the produced casing-head gas has a high BTU content making it the primary source of our natural gas liquids. The oil and gas are primarily from five producing intervals; the Upper and Lower Spraberry, the Wolfcamp, the Strawn, and the Atoka, at depths ranging from 6,700 feet to 11,300 feet. This region is managed from our office in Midland, Texas. As of December 31, 2022, we had 557 wells (254 net) in the West Texas area, of which 310 wells are operated by us. The average net daily production in Our West Texas Region at year-end 2022 was 3,257 Boe. As of December 31, 2022, we had 13,256 MBoe of proved reserves in the West Texas area, or 79.3 % of our total proved reserves. We maintain an acreage position of approximately 16,171 gross (9,266 net) acres in the Permian Basin in West Texas, primarily in Reagan, Upton, Martin, and Midland counties, and believe this acreage has significant resource potential for additional horizontal drilling in the Spraberry, Jo Mill, and Wolfcamp pay intervals. We operate a field service group in this region utilizing nine workover rigs, three hot oiler trucks, and one kill truck. Services, including well service support, site preparation, and construction services for drilling and workover operations, are provided to third-party operators as well as utilized in our own operated wells and locations.
In the first three quarters of 2023, the Company has added 22 completed horizontal wells to its West Texas proved-producing portfolio through our participation in 15 wells in Reagan County, five in Martin County, and two in Upton County. Ten of the 15 wells in Reagan County are operated by Civitas Resources (formerly Hibernia Energy III, LLC), located on our Brynn Tract, and five are operated by DE IV Operating, LLC (Double Eagle), located on our Prime East Tract. The five wells in Martin County are operated by ConocoPhillips on our Schenecker A Tract, and the two in Upton County, operated by Apache Corporation, are our Mt. Moran wells. The Company has invested approximately $78 million in these 22 horizontals and owns an average 32.2% working interest.
In the fourth quarter of 2023, the Company is participating in an additional 18 horizontal wells operated by Double Eagle, located in our Hughes Alpine area of Reagan County (Studley Tracts): we are participating with 6.82% working interest in 6 two-mile-long horizontals that are expected to be on production in December of this year, and participating with 20% interest in 12 two and a half-mile-long laterals that are expected to be on production in February of 2024. In total, the Company is investing approximately $27 million in these 18 new horizontals and their associated facilities.
As a result of the recent success of wells completed by Double Eagle and Civitas in Reagan County, as well as existing analogs and relatively high oil prices, both of these companies have accelerated their development plans in the area where we have significant leasehold acreage. Double Eagle and Civitas each have three rigs running in the area and in the fourth quarter of 2023, we expect to begin drilling an additional 20 wells with Double Eagle and 14 wells with Civitas. The Company has an average of approximately 50% interest in six wells (Prime West), 8.3% interest in twelve wells (Kramer and O’Bannon), less than 1% interest in two wells (State Pink Floyd), and an average of 41% interest in 14 wells (Christi). In total, we expect to invest $84 million in these 34 wells that are all expected to be on production in the second quarter of 2024.
In addition to the drilling activity described above, we expect another 12 wells, operated by Double Eagle, to begin drilling on adjacent or nearby acreage in the first quarter of 2024 with an expected investment by the Company of $48 million for our 50% interest in these wells.
In summary, we are investing approximately $27 million in 18 horizontal wells operated by Double Eagle in Reagan County that are expected to begin production by February 2024, and preparing to invest $84 million in 14 wells with Civitas Resources and 20 wells with Double Eagle in Reagan County that are expected to begin drilling in the fourth quarter of 2023 and have production starts in the second quarter of 2024. In addition, we expect the drilling of 12 more horizontal wells to begin in the first quarter of 2024, carrying a net capital requirement of approximately $48 million. Therefore, the total capital commitment for wells to spud by the end of the first quarter of 2024 is approximately $159 million.
Reserves
Our interests in proved developed and undeveloped oil and gas properties have been evaluated by Ryder Scott Company, L.P. for each of the three years ended December 31, 2022. The professional qualifications of the technical persons primarily responsible for overseeing the preparation of the reserve estimates can be found in Exhibit 99.1, the Ryder Scott Company, L.P. Report on Registrant’s Reserves Estimates. In matters related to the preparation of our reserve estimates, our district managers report to the Engineering Data manager, who maintains oversight and compliance responsibility for the internal reserve estimate process and provides oversight for the annual preparation of reserve estimates of 100% of our year-end reserves by our independent third-party engineers, Ryder Scott Company, L.P. The members of our district and central groups consist of degreed engineers and geologists with between approximately twenty and thirty-five years of industry experience, and between eight and twenty-five years of
experience managing our reserves. Our Engineering Data manager, the technical person primarily responsible for overseeing the preparation of reserves estimates, has over thirty years of experience, holds a Bachelor’s degree in Geology and an MBA in finance and is a member of the Society of Petroleum Engineers and American Association of Petroleum Geologist. All of our reserves are located within the continental United States. The following table summarizes our oil and gas reserves at each of the respective dates:
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The following table summarizes our oil and gas reserves at each of the respective dates:
| Reserve Category | ||||||||||||||||||||||||||||||||||||||||||||||||
| Proved Developed | Proved Undeveloped | Total | ||||||||||||||||||||||||||||||||||||||||||||||
| As of December 31, |
Oil (MBbls) |
NGLs (MBbls) |
Gas (MMcf) |
Total (MBoe) |
Oil (MBbls) |
NGLs (MBbls) |
Gas (MMcf) |
Total (MBoe) |
Oil (MBbls) |
NGL (MBbls) |
Gas (MMcf) |
Total (MBoe) |
||||||||||||||||||||||||||||||||||||
| 2020 |
2,684 | 2,258 | 13,633 | 7,214 | 1,784 | 787 | 3,897 | 3,221 | 4,468 | 3,045 | 17,530 | 10,435 | ||||||||||||||||||||||||||||||||||||
| 2021 |
5,386 | 2,882 | 23,902 | 12,252 | — | — | — | — | 5,386 | 2,882 | 23,902 | 12,252 | ||||||||||||||||||||||||||||||||||||
| 2022 |
4,143 | 2,497 | 22,277 | 10,353 | 3,028 | 1,833 | 9,030 | 6,366 | 7,171 | 4,330 | 31,307 | 16,719 | ||||||||||||||||||||||||||||||||||||
| (a) | In computing total reserves on a barrels of oil equivalent (Boe) basis, gas is converted to oil based on its relative energy content at the rate of six Mcf of gas to one barrel of oil and NGLs are converted based upon volume; one barrel of natural gas liquids equals one barrel of oil. |
In 2020, in West Texas we participated in the drilling of seven wells: one with PrimeEnergy Resources Corporation for 8.6% interest which was brought into production in July of 2020, and six wells with Apache on our Kashmir tract with an average of 47.5% interest that were drilled but not completed at year-end and therefore classified as Proved Undeveloped in the year-end 2020 reserve report. The Company invested approximately $8.0 million in these seven wells in 2020. Also in 2020, reserves were added in West Texas through the addition of 11 horizontal wells completed in Midland County, Texas, in which we receive 0.56% to 1% over-riding royalty interest. In our Gulf Coast Region, in 2020, we successfully recompleted one operated well in the Segno field of Polk County, Texas with a 72.5% interest.
On December 31, 2020, in total, the Company had 3,221 Mboe of proved undeveloped reserves attributable to 13 wells operated by others, 10 of which were drilled but not completed by year-end 2020, and three that were not drilled until 2021. The three new horizontals along with the six uncompleted wells at year-end were brought online in late September and early October of 2021. These successful new wells are on our Kashmir tract in Upton County, Texas operated by Apache Corporation. These nine PUD wells at year-end 2020 accounted for 3,127 Mboe of the total undeveloped. The four other PUD wells, drilled but not completed at year-end 2020, are located in Grady County, Oklahoma, and accounted for 95 Mboe of the total undeveloped reserves.
In 2021, in West Texas, we participated with Apache in the drilling of three additional horizontals on the Kashmir Tract in Upton County, Texas, and completed these three wells in September of 2021 along with six other wells drilled in 2020 on the same lease that were drilled but uncompleted at year-end. The Company has an average of 47.8% interest in these nine wells and invested approximately $30 million in these horizontal wells. Also in 2021, the Company participated with Ovintiv Mid-Continent for 11.25% interest in four two-mile horizontal wells in Canadian County, Oklahoma. Twelve of these thirteen horizontal wells were completed and placed into production in the fourth quarter of 2021. One of the Ovintiv wells had a casing leak issue and has been temporarily abandoned. The Company invested approximately $32 million in these thirteen wells. In addition, in 2021, the Company added minor reserves through over-riding royalty interest in two wells drilling and completed in Grady County, Oklahoma.
On December 31, 2021, the Company had 159 Mboe of proved-developed shut-in reserves attributable to three horizontals drilled and completed in Canadian County, Oklahoma, but not yet online at year-end. These reserves were converted to proved producing in the first quarter of 2022. At year-end 2021, we did not include proved-undeveloped reserves in our reserve report because we had not yet received definitive drilling proposals from third-party operators the fifteen horizontal wells that we planned to participate in located primarily in West Texas.
In 2022, the Company completed eight horizontal wells: four located in Irion County, West Texas, operated by SEM Operating Company, in which we have 10.13% interest, and four located in Canadian County, Oklahoma, operated by Ovintiv Mid-Continent, Inc., in which we have an average 9% interest. Our investment in these eight wells was approximately $4 million and all were brought on production in August of 2022. In addition, the Company added reserves through 15 wells in which we have various minor over-riding royalty interests; eight of these are located in West Texas and seven are located in Oklahoma.
In the fourth quarter of 2022, we began participation in the drilling of 20 horizontal wells located in West Texas: In Martin County, we participated with ConocoPhillips in the drilling of five 2.5-mile-long horizontal laterals (Schenecker A Tract) in which the Company has 20.83% interest with a capital investment of approximately $12.1 million. In Reagan County, we participated with Hibernia Energy III in 10 two-mile horizontals (Brynn Tract) with 25% interest with an investment of approximately $25.6 million. Also in Reagan County, we participated with Double Eagle (DE IV) in five two-mile-long horizontals (Prime East Tract) with nearly 50% interest and carried a net capital outlay of approximately $23.4 million. All twenty of these West Texas wells were brought on production by the end of the third quarter of 2023.
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In the first quarter of 2023, the Company joined Ovintiv USA, Inc. in the drilling of three 3-mile-long horizontal wells in Canadian County, Oklahoma with 1.96% interest, investing approximately $645,000 (Redhead tract). These three wells were put online in June of 2023. Also in the first quarter, the Company began participation with Apache Corporation in the drilling of two 3-mile-long horizontals in Upton County, Texas (Mt. Moran). We have 49.4% interest in these wells and have made a capital investment of approximately $16.1 million, and both were brought online in October.
At year-end 2022, the Company had 6,366 Mboe of proved undeveloped reserves all attributable to the 25 horizontal wells described above. In total, the Company will have invested $78 million in these 25 horizontal wells, all of which have been completed and began producing by mid-October.
Summarized in the table below (in thousands of dollars) are the estimated future net revenue (using current prices and costs as of those dates) and the present value of future net revenue (at a 10% discount for estimated timing of cash flow) for our proved developed and proved undeveloped oil and gas reserves at the end of each of the three years ended December 31, 2022:
| Proved Developed | Proved Undeveloped | Total | ||||||||||||||||||||||||||||||
| As of December 31, |
Future Net Revenue |
Present Value 10 Of Future Net Revenue |
Future Net Revenue |
Present Value 10 Of Future Net Revenue |
Future Net Revenue |
Present Value 10 Of Future Net Revenue |
Present Value 10 Of Future Income Taxes |
Standardized Measure of Discounted Cash flow |
||||||||||||||||||||||||
| 2020 | $ | 43,886 | $ | 34,717 | $ | 37,346 | $ | 21,823 | $ | 81,232 | $ | 56,539 | $ | 14,920 | $ | 41,619 | ||||||||||||||||
| 2021 | $ | 275,227 | $ | 171,906 | $ | — | $ | — | $ | 275,227 | $ | 171,906 | $ | 36,100 | $ | 135,806 | ||||||||||||||||
| 2022 | $ | 320,146 | $ | 192,688 | $ | 200,790 | $ | 118,081 | $ | 520,936 | $ | 310,769 | $ | 66,233 | $ | 244,536 | ||||||||||||||||
The PV10 Value represents the discounted future net cash flows attributable to our proved oil and gas reserves before income tax, discounted at 10%. Although this measure is not in accordance with U.S. generally accepted accounting principles (“GAAP”), we believe that the presentation of the PV10 Value is relevant and useful to investors because it presents the discounted future net cash flow attributable to proved reserves prior to taking into account corporate future income taxes and the current tax structure. We use this measure when assessing the potential return on investment related to oil and gas properties. The PV10 of future income taxes represents the sole reconciling item between this non-GAAP PV10 Value versus the GAAP measure presented in the standardized measure of discounted cash flow. A reconciliation of these values is presented in the last three columns of the table above. The standardized measure of discounted future net cash flows represents the present value of future cash flows attributable to proved oil and natural gas reserves after income tax, discounted at 10%.
“Proved developed” oil and gas reserves are reserves that can be expected to be recovered from existing wells with existing equipment and operating methods. “Proved undeveloped” oil and gas reserves are reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.
In accordance with U.S. generally accepted accounting principles, product prices are determined using the twelve-month average oil and gas index prices, calculated as the unweighted arithmetic average for the first day of the month price for each month, adjusted for oilfield or gas gathering hub and wellhead price differentials (e.g. grade, transportation, gravity, sulfur, and basic sediment and water) as appropriate. Also, in accordance with SEC specifications and U.S. generally accepted accounting principles, changes in market prices subsequent to December 31 are not considered.
While it may be reasonably anticipated that the prices received for the sale of our production may be higher or lower than the prices used in this evaluation, as described above, and the operating costs relating to such production may also increase or decrease from existing levels, such possible changes in prices and costs were, in accordance with rules adopted by the SEC, omitted from consideration in making this evaluation for the SEC case. Actual volumes produced, prices received and costs incurred may vary significantly from the SEC case.
Natural gas prices, based on the twelve-month average of the first of the month Henry Hub index price, were $6.358 per MMBtu in 2022 as compared to $3.598 per MMBtu in 2021, and $1.985 per MMBtu in 2020. Oil prices, based on the West Texas Intermediate (WTI) Light Sweet Crude first-of-the-month average spot price, were $93.67 per barrel in 2022 as compared to $66.56 per barrel in 2021, and $39.57 per barrel in 2020. Since January 1, 2022, we have not filed any estimates of our oil and gas reserves with, nor were any such estimates included in any reports to, any federal authority or agency, other than the Securities and Exchange Commission.
RECENT ACTIVITIES
The Company’s activities include development and exploratory drilling. Our strategy is to develop the Company’s oil and gas reserves primarily through horizontal drilling. This strategy includes targeting reservoirs with high initial production rates and cash flow as well as targeting reservoirs with somewhat lower average initial production rates but steady production and higher expected return on investment. We believe that today’s horizontal drilling and completion technologies provide superior economic results compared to vertical development delivering higher production rates through greater contact and stimulation of a larger volume of reservoir rock while minimizing the surface footprint required to develop those same reserves.
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Maintaining a strong balance sheet and ample liquidity are key components of our business strategy. In 2023, we intend to continue our focus on preserving financial flexibility and ample liquidity as we manage the risks facing our industry. Our capital budget for the year is reflective of current commodity prices and has been established based on an expectation of available cash flows, with any cash flow deficiencies expected to be funded by borrowings under our revolving credit facility. As we have done historically to preserve or enhance liquidity, we may adjust our capital program throughout the year, divest non-strategic assets, or enter into strategic joint ventures.
We are actively developing our leasehold acreage in West Texas and Oklahoma and in 2023, through the third quarter, we have brought on production 25 new horizontal wells. Current activity includes the drilling of 18 wells in Reagan County, and an additional 34 wells anticipated to spud by year-end. The following is a description of recent, current, and expected near-term drilling activities. Note, the drilling activities described below were previously described on a district basis in the District Information section above.
In the fourth quarter of 2022, we began participation in 20 horizontal wells in West Texas that have been completed and put on production in 2023: in Martin County, we participated with ConocoPhillips in five 2.5-mile-long horizontal wells (Schenecker A Tract) with 20.83% interest, investing approximately $12.1 million, in Reagan County, we participated with Hibernia Energy III in 10 two-mile horizontals (Brynn Tract) with 25% interest, investing approximately $25.6 million, and, also in Reagan County, we partnered with Double Eagle (DE IV) in five two-mile-long horizontals (Prime East Tract) with nearly 50% interest and invested approximately $23.4 million. All 20 of these West Texas wells were put into production in 2023.
In the first quarter of 2023, the Company joined Ovintiv USA, Inc. in the drilling of three 3-mile-long horizontal wells in Canadian County, Oklahoma with 1.96% interest and invested approximately $645,000. Production of these three wells began in June. Also in the first quarter of 2023, the Company began participation with Apache Corporation in the drilling of two 3-mile-long horizontals in Upton County, Texas (Mt. Moran wells). The Company has a 49.4% interest in these two wells, has invested approximately $16.1 million and the wells were brought on production in October.
In total, the Company has invested approximately $78 million in these 25 horizontal wells and their associated facilities. In December of 2022, we prepaid $32 million toward drilling costs, and the remaining $46 million in estimated drilling, completion and facilities expenses will be incurred as billed in 2023.
The success of the 22 horizontals in West Texas described above is leading to additional near-term horizontal drilling across five leasehold blocks in three counties. Both Civitas Resources and Double Eagle have accelerated their development plans and have six rigs running in the area. We are currently participating with Double Eagle in 18 wells in Reagan County and will invest an estimated $27 million in these wells that are expected to be completed and online in February 2024. In addition, we have received AFEs from Double Eagle for 20 additional horizontals in Reagan County. We will have varying interests in these 20 wells and will make an estimated capital investment of $34 million in them. Also expected soon are AFEs from Civitas for 14 wells in Reagan County where we will have an average of 41% working interest and will invest approximately $50 million. The total of these two near-term projects is $84 million. In addition, we expect drilling proposals from four operators for the development of an additional 35 horizontal wells in West Texas expected to spud in the first three quarters of 2024. Our interest in these 35 wells will vary from 20% to 50% and we expect a capital outlay related to these wells and their facilities of approximately $143 million.
All of the current and expected near-term activities described above encompass the drilling, completion, stimulation, and facilities of 90 new horizontal wells to be added to our proved-producing portfolio. These 90 wells will require an estimated $260 million net capital investment over the next two years. In addition, we have identified 27 horizontal locations that are a natural progression of development for three project areas in Upton and Reagan counties and are anticipated to be drilled in the 2025-2026 timeframe and will require a net investment of approximately $100 million.
In summary, we have invested $78 million in 25 new horizontals this year that are all producing, and we plan to invest about $400 million in horizontal development over the next several years. Included in this $400 million estimate are the above-described investment of $27 million for 18 wells currently in the process of being completed, the $84 million in near-term development drilling for 34 wells (20 wells with Double Eagle and 14 wells with Civitas), the $143 million in expected investment for 35 wells to spud in the first three quarters of 2024, the $100 million investment in 27 drill-sites that are a natural progression of leasehold development, plus approximately $40 million in additional investments for proved and probable drill-sites that are not yet scheduled for development.
RESULTS OF OPERATIONS:
We reported net income of $22.2 million, or $11.95 per share and $10.7 million, or $5.84 per share for the nine and three months ended September 30, 2023, respectively, as compared to $35.3 million, or $17.95 per share and $13.2 million, or $6.79 per share for the nine and three months ended September 30, 2022, respectively. Current year net income reflects changes in production and commodity prices over the three and nine months ended September 30, 2022, fluctuations in gains related to the sale of assets and changes related to the valuation of derivative instruments. The significant components of income and expense are discussed below.
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Oil, gas and NGLs sales decreased $2.0 million, or 5.9% from $34.0 million for the three months ended September 30, 2022 to $32.0 million for the three months ended September 30, 2023, and $27.1 million, or 26.4% from $102.8 million for the nine months ended September 30, 2022 to $75.7 million for the nine months ended September 30, 2023. Sales vary due to changes in volumes of production sold and realized commodity prices. Our oil production reflects the natural decline in production from our previously existing wells offset by the new wells placed in production during 2023.
The following tables summarizes the primary components of production volumes and average sales prices realized for the three and six months ended September 30, 2023 and 2022 (excluding realized gains and losses from derivatives).
| Nine months ended September 30, | ||||||||||||||||
| 2023 | 2022 | Increase / (Decrease) |
Increase / (Decrease) |
|||||||||||||
| Barrels of Oil Produced |
813,561 | 752,500 | 61,061 | 8.1 | % | |||||||||||
| Average Price Received |
$ | 76.14 | $ | 100.39 | $ | (24.25 | ) | (24.2 | )% | |||||||
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| Oil Revenue (In 000’s) |
$ | 61,948 | $ | 75,546 | $ | (13,598 | ) | (18.0 | )% | |||||||
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| Mcf of Gas Sold |
2,766,128 | 2,456,800 | 309,328 | 12.6 | % | |||||||||||
| Average Price Received |
$ | 1.97 | $ | 6.01 | $ | (4.04 | ) | (67.2 | )% | |||||||
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| Gas Revenue (In 000’s) |
$ | 5,452 | $ | 14,762 | $ | (9,310 | ) | (63.1 | )% | |||||||
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| Barrels of Natural Gas Liquids Sold |
412,487 | 332,400 | 80,087 | 24.1 | % | |||||||||||
| Average Price Received |
$ | 20.18 | $ | 37.54 | $ | (17.36 | ) | (46.2 | )% | |||||||
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| Natural Gas Liquids Revenue (In 000’s) |
$ | 8,323 | $ | 12,477 | $ | (4,154 | ) | (33.3 | )% | |||||||
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| Total Oil & Gas Revenue (In 000’s) |
$ | 75,723 | $ | 102,785 | $ | (27,062 | ) | (26.3 | )% | |||||||
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| Three months ended September 30, | ||||||||||||||||
| 2023 | 2022 | Increase / (Decrease) |
Increase / (Decrease) |
|||||||||||||
| Barrels of Oil Produced |
323,188 | 244,500 | 78,688 | 32.2 | % | |||||||||||
| Average Price Received |
$ | 81.69 | $ | 95.72 | $ | (14.03 | ) | (14.7 | )% | |||||||
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|||||||||||
| Oil Revenue (In 000’s) |
$ | 26,402 | $ | 23,403 | $ | 2,999 | 12.8 | % | ||||||||
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| Mcf of Gas Sold |
1,080,588 | 879,800 | 200,788 | 22.8 | % | |||||||||||
| Average Price Received |
$ | 2.29 | $ | 7.23 | $ | (4.94 | ) | (68.3 | )% | |||||||
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|||||||||||
| Gas Revenue (In 000’s) |
$ | 2,472 | $ | 6,359 | $ | (3,887 | ) | (61.1 | )% | |||||||
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| Barrels of Natural Gas Liquids Sold |
161,003 | 122,400 | 38,603 | 31.5 | % | |||||||||||
| Average Price Received |
$ | 19.56 | $ | 34.35 | $ | (14.79 | ) | (43.1 | )% | |||||||
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| Natural Gas Liquids Revenue (In 000’s) |
$ | 3,149 | $ | 4,204 | $ | (1,055 | ) | (25.1 | )% | |||||||
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| Total Oil & Gas Revenue (In 000’s) |
$ | 32,023 | $ | 33,966 | $ | (1,943 | ) | (5.7 | )% | |||||||
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Oil, Natural Gas and NGL Derivatives We do not apply hedge accounting to any of our commodity based derivatives, thus changes in the fair market value of commodity contracts held at the end of a reported period, referred to as mark-to-market adjustments, are recognized as unrealized gains and losses in the accompanying consolidated statements of operations. As oil and natural gas prices remain volatile, mark-to-market accounting treatment creates volatility in our revenues. The following table summarizes the results of our derivative instruments for the three and nine months ended September 2023 and 2022:
| Three Months Ended September 30, |
Nine Months Ended September 30, |
|||||||||||||||
| 2023 | 2022 | 2023 | 2022 | |||||||||||||
| Oil derivatives – realized losses |
$ | — | $ | (2,668 | ) | $ | (590 | ) | $ | (10,389 | ) | |||||
| Oil derivatives – unrealized gains |
— | 5,958 | 769 | 2,718 | ||||||||||||
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| Total gains (losses) on oil derivatives |
$ | — | $ | 3,290 | $ | 179 | $ | (7,671 | ) | |||||||
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| Natural gas derivatives – realized gains (losses) |
$ | — | $ | (1,617 | ) | $ | 24 | $ | (3,603 | ) | ||||||
| Natural gas derivatives – unrealized gains (losses) |
— | 166 | 211 | (800 | ) | |||||||||||
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| Total gains (losses) on natural gas derivatives |
$ | — | $ | (1,451 | ) | $ | 235 | $ | (4,403 | ) | ||||||
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| Total gains (losses) on oil and natural gas derivatives |
$ | — | $ | 1,839 | $ | 414 | $ | (12,074 | ) | |||||||
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Prices received for the nine months ended September 30, 2023 and 2022, respectively, including the impact of derivatives were:
| 2023 | 2022 | |||||||
| Oil Price |
$ | 75.42 | $ | 86.59 | ||||
| Gas Price |
$ | 1.98 | $ | 4.54 | ||||
| NGLS Price |
$ | 20.18 | $ | 37.54 | ||||
Oil and gas production expense increased $1.4 million, or 21.5% from $6.5 million for the three months ended September 30, 2022 to $7.9 million for the three months ended September 30, 2023, and increased $0.3 million, or 1.4% from $20.9 million for the nine months ended September 30, 2022 to $21.2 million for the nine months ended September 30, 2023. These changes reflect the cost savings related to wells that have been plugged offset by rising service costs and additional costs related to the new wells that have been placed on production.
Production and ad valorem taxes decreased $0.8 million, or 36.4% from $2.2 million for the three months ended September 30, 2022 to $1.4 million for the three months ended September 30, 2023, and decreased $0.4 million, or 7.0% from $5.7 million for the nine months ended September 30, 2022 to $5.3 million for the nine months ended September 30, 2023. These decreases reflect the changes in oil and gas revenues in the related periods.
Field service income decreased $0.2 million or 5.7% from $3.5 million for the third quarter 2022 to $3.3 million for the third quarter 2023 and increased $1.4 million, or 14.0% from $10.0 million for the nine months ended September 30, 2022 to $11.4 million for the nine months ended September 30, 2023. Workover rig services, hot oil treatments, saltwater hauling and disposal represent the bulk of our field service operations. These changes reflect the variance in equipment utilization and service rates during these periods.
Field service expense increased $0.5 million or 18.5% from $2.7 million for the third quarter 2022 to $3.2 million for the third quarter 2023 and increased $1.0 million, or 11.5% from $8.7 million for the nine months ended September 30, 2022 to $9.7 million for the nine months ended September 30, 2023. Field service expenses primarily consist of wages and vehicle operating expenses which have fluctuated during the three and nine months ended September 30, 2023 compared with the same periods of 2022. These changes reflect the variance in equipment utilization during these periods.
Depreciation, depletion and amortization expense increased $1.3 million or 17.1% from $7.6 million for the third quarter 2022 to $8.9 million for the third quarter 2023 and increased $1.5 million, or 7.0% from $21.4 million for the nine months ended September 30, 2022 to $22.9 million for the nine months ended September 30, 2023. This increase reflects the expense related to the new wells placed on production in 2023.
General and administrative expense decreased $3.4 million, or 29.6% from $11.5 million for the nine months ended September 30, 2022 to $8.1 million for the nine months ended September 30, 2023, and increased $0.2 million, or 8.0% from $2.5 million for the three months ended September 30, 2022 to $2.7 million for the three months ended September 30, 2023. These changes are primarily related to employee compensation and benefits.
Interest expense decreased $0.4 million, or 50.0% from $0.8 million for the nine months ended September 30, 2022 to $0.4 million for the nine months ended September 30, 2023, and decreased $0.2 million, or 66.7% from $0.3 million for the three months ended September 30, 2022 to $0.1 million for the three months ended September 30, 2023. This decrease reflects the increase in rates and lower current borrowings under our revolving credit agreement.
Income tax expense for the September 30, 2023 and 2022 periods varied due to the change in net income.
LIQUIDITY AND CAPITAL RESOURCES
Maintaining a strong balance sheet and ample liquidity are key components of our business strategy. For 2023, we will continue our focus on preserving financial flexibility and ample liquidity as we manage the risks facing our industry. Our 2023 capital budget is reflective of commodity prices and has been established based on an expectation of available cash flows, with any cash flow deficiencies expected to be funded by borrowings under our revolving credit facility. As we have done historically to preserve or enhance liquidity, we may adjust our capital program throughout the year, divest assets, or enter into strategic joint ventures.
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Table of Contents
Our primary sources of liquidity are cash generated from our operations, through our producing oil and gas properties, field services business and sales of acreage. Net cash provided by operating activities and proceeds from the sale of properties for the nine months ended September 30, 2023 was $78.1 million, compared to $62.7 million in the prior year.
Excluding the effects of significant unforeseen expenses or other income, our cash flow from operations fluctuates primarily because of variations in oil and gas production and prices or changes in working capital accounts. Our oil and gas production will vary based on actual well performance but may be curtailed due to factors beyond our control.
Our realized oil and gas prices vary due to world political events, supply and demand of products, product storage levels, and weather patterns. We sell the majority of our production at spot market prices. Accordingly, product price volatility will affect our cash flow from operations. To mitigate price volatility, we sometimes lock in prices for some portion of our production through the use of derivatives.
Our credit agreement required us to hedge a portion of our production as forecasted for the PDP reserves included in our borrowing base review engineering reports. If the borrowing base utilization percentage is less than 15% of total available borrowings, the Company is not required to enter into any hedge agreements. The Company has no outstanding borrowings and all hedge agreements were settled or terminated prior to March 31, 2023. Additional drilling and future development plans will be established based on an expectation of available cash flows from operations and availability of funds under our revolving credit facility.
The Company maintains a Credit Agreement providing for a reserves-based line of credit totaling $300 million, with a current borrowing base of $65 million. As of November 15, 2023, the Company has no outstanding borrowings under this line. The bank reviews the borrowing base semi-annually and, at their discretion, may decrease or propose an increase to the borrowing base relative to a re-determined estimate of proved oil and gas reserves. The next borrowing base review is scheduled for December 2023. Our oil and gas properties are pledged as collateral for the line of credit and we are subject to certain financial and operational covenants defined in the agreement. We are currently in compliance with these covenants and expect to be in compliance over the next twelve months. If we do not comply with these covenants on a continuing basis, the lenders have the right to refuse to advance additional funds under the facility and/or declare all principal and interest immediately due and payable. Our borrowing base may decrease as a result of lower natural gas or oil prices, operating difficulties, declines in reserves, lending requirements or regulations, the issuance of new indebtedness or for other reasons set forth in our revolving credit agreement. In the event of a decrease in our borrowing base due to declines in commodity prices or otherwise, our ability to borrow under our revolving credit facility may be limited and we could be required to repay any indebtedness in excess of the re-determined borrowing base.
The majority of our capital spending is discretionary, and the ultimate level of expenditures will be dependent on our assessment of the oil and gas business environment, the number and quality of oil and gas prospects available, the market for oilfield services, and oil and gas business opportunities in general.
The Company has a stock repurchase program in place, spending under this program during the first nine months of 2023 was $6.6 million. The Company expects continued spending under the stock repurchase program in 2023.
| Item 3. | QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK |
The Company is a smaller reporting company and no response is required pursuant to this Item.
| Item 4. | CONTROLS AND PROCEDURES |
As of the end of the current reported period covered by this report, the Company carried out an evaluation, under the supervision and with the participation of the Company’s management, including the Company’s Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of the Company’s disclosure controls and procedures pursuant to Rules 13a-15 and 15d-15 of the Securities Exchange Act of 1934 (the “Exchange Act”). Based upon that evaluation, the Chief Executive Officer and Chief Financial Officer concluded that the Company’s disclosure controls and procedures are effective with respect to the recording, processing, summarizing and reporting, within the time periods specified in the Commission’s rules and forms, of information required to be disclosed by the Company in the reports that it files or submits under the Exchange Act.
There were no changes in the Company’s internal control over financial reporting that occurred during the first nine months of 2023 that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.
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Table of Contents
PART II—OTHER INFORMATION
| Item 1. | LEGAL PROCEEDINGS |
None.
| Item 1A. | RISK FACTORS |
The Company is a smaller reporting company and no response is required pursuant to this Item.
| Item 2. | UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS |
There were no sales of equity securities by the Company during the period covered by this report. There was no purchase of equity securities by the Company during the period covered by this report.
| 2023 Month |
Number of Shares |
Average Price Paid per share |
Maximum Number of Shares that May Yet Be Purchased Under The Program at Month—End (1) |
|||||||||
| January |
9,500 | $ | 90.36 | 45,044 | ||||||||
| February |
3,000 | $ | 90.32 | 42,044 | ||||||||
| March |
18,940 | $ | 85.44 | 23,104 | ||||||||
| April |
10,560 | $ | 86.21 | 12,544 | ||||||||
| May |
11,000 | $ | 86.69 | 1,544 | ||||||||
| June |
7,500 | $ | 100.35 | 294,044 | ||||||||
| July |
4,000 | $ | 94.00 | 290,044 | ||||||||
| August |
4,000 | $ | 98.09 | 286,044 | ||||||||
| September |
4,000 | $ | 109.73 | 282,044 | ||||||||
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| Total/Average |
72,500 | $ | 90.64 | |||||||||
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| (1) | In December 1993, we announced that the Board of Directors authorized a stock repurchase program whereby we may purchase outstanding shares of the common stock from time-to-time, in open market transactions or negotiated sales. On October 31, 2012, June 13, 2018 and June 7, 2023, the Board of Directors of the Company approved an additional 500,000, 200,000 and 300,000 shares respectively, of the Company’s stock to be included in the stock repurchase program. A total of 4,000,000 shares have been authorized to date under this program. Through September 30, 2023, a total of 3,717,956 shares have been repurchased under this program for $89,053,479 at an average price of $23.95 per share. Additional purchases of shares may occur as market conditions warrant. We expect future purchases will be funded with internally generated cash flow or from working capital. |
| Item 3. | DEFAULTS UPON SENIOR SECURITIES |
None
| Item 4. | RESERVED |
| Item 5. | OTHER INFORMATION |
None
23
Table of Contents
| Item 6. | EXHIBITS |
The following exhibits are filed as a part of this report:
24
Table of Contents
SIGNATURES
Pursuant to the requirements of the Securities and Exchange Act of 1934, Registrant has duly caused this Report to be signed on its behalf by the undersigned thereunto duly authorized.
| PrimeEnergy Resources Corporation | ||
| (Registrant) | ||
| November 17, 2023 |
/s/ Charles E. Drimal, Jr. | |
| (Date) |
Charles E. Drimal, Jr. | |
| President | ||
| Principal Executive Officer | ||
| /s/ Beverly A. Cummings | ||
| November 17, 2023 |
Beverly A. Cummings | |
| Executive Vice President | ||
| Principal Financial Officer | ||
25