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 | ||||||
PrimeEnergy Resources Corporation
Index to Form 10-Q
June 30, 2023
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. |
| (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. |
1
| (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. |
2
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
Item 1. |
FINANCIAL STATEMENTS |
June 30, 2023 (Unaudited) |
December 31, 2022 |
|||||||
ASSETS |
||||||||
Current assets: |
||||||||
Cash and cash equivalents |
$ | $ | ||||||
Accounts receivable, net |
||||||||
Prepaid obligations |
||||||||
Due from related parties |
||||||||
Derivative asset |
||||||||
Other current assets |
||||||||
Total current assets |
||||||||
Properties and equipment: |
||||||||
Proved oil and gas properties, using the successful efforts method of accounting |
||||||||
Other property |
||||||||
Accumulated depletion and depreciation |
( |
) | ( |
) | ||||
Total properties, net |
||||||||
Right-of-use |
||||||||
Other assets |
||||||||
Total Assets |
$ | $ | ||||||
LIABILITIES AND EQUITY |
||||||||
Current liabilities: |
||||||||
Accounts payable |
$ | $ | ||||||
Accrued liabilities |
||||||||
Current portion of asset retirement and other long-term obligations |
||||||||
Derivative liability |
||||||||
Total current liabilities |
||||||||
Long-term bank debt |
||||||||
Asset retirement obligations |
||||||||
Deferred income taxes |
||||||||
Other long-term obligations |
||||||||
Total Liabilities |
||||||||
COMMITMENTS AND CONTINGENCIES |
||||||||
Equity: |
||||||||
Common stock, $ |
||||||||
Additional paid in capital |
||||||||
Retained earnings |
||||||||
Treasury stock, at cost; |
( |
) | ( |
) | ||||
Total Equity |
||||||||
Total Liabilities and Equity |
$ | $ | ||||||
Three Months Ended June 30, |
Six Months Ended June 30, |
|||||||||||||||
2023 |
2022 |
2023 |
2022 |
|||||||||||||
Revenues: |
||||||||||||||||
Oil |
$ | $ | $ | $ | ||||||||||||
Natural gas |
||||||||||||||||
Natural gas liquids |
||||||||||||||||
Field service |
||||||||||||||||
Realized loss on derivative instruments, net |
( |
) | ( |
) | ( |
) | ||||||||||
Unrealized gain (loss) on derivative instruments, net |
( |
) | ||||||||||||||
Other income |
||||||||||||||||
Total revenues |
||||||||||||||||
Costs and expenses: |
||||||||||||||||
Oil and gas production |
||||||||||||||||
Production and ad valorem taxes |
||||||||||||||||
Field service |
||||||||||||||||
Depreciation, depletion and amortization |
||||||||||||||||
Accretion of discount on asset retirement obligations |
||||||||||||||||
General and administrative |
||||||||||||||||
Total costs and expenses |
||||||||||||||||
Gain on sale and exchange of assets |
||||||||||||||||
Income from operations |
||||||||||||||||
Other income (expense) |
||||||||||||||||
Interest expense |
( |
) | ( |
) | ( |
) | ( |
) | ||||||||
Interest income |
||||||||||||||||
Income before income taxes |
||||||||||||||||
Income tax provision |
||||||||||||||||
Net income |
$ | $ | $ | $ | ||||||||||||
Net income per share attributable to common stockholders: |
||||||||||||||||
Basic |
$ | $ | $ | $ | ||||||||||||
Diluted |
$ | $ | $ | $ | ||||||||||||
Weighted average shares outstanding: |
, | |||||||||||||||
Basic |
||||||||||||||||
Diluted |
||||||||||||||||
Common Stock |
Additional Paid-In Capital |
Retained Earnings |
Treasury Stock |
Total Equity |
||||||||||||||||||||
Shares Outstanding |
Common Stock |
|||||||||||||||||||||||
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 |
$ | $ | $ | $ | ( |
) | $ | |||||||||||||||||
Common Stock |
Additional Paid-In Capital |
Retained Earnings |
Treasury Stock |
Total Equity |
||||||||||||||||||||
Shares Outstanding |
Common Stock |
|||||||||||||||||||||||
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 |
$ | $ | $ | $ | ( |
) | $ | |||||||||||||||||
2023 |
2022 |
|||||||
Cash Flows from Operating Activities: |
||||||||
Net Income |
$ | $ | ||||||
Adjustments to reconcile net income to net cash provided by operating activities: |
||||||||
Depreciation, depletion, amortization and accretion on discounted liabilities |
||||||||
Gain on sale and exchange of assets |
( |
) | ( |
) | ||||
Accretion of discount on asset retirement obligations |
||||||||
Unrealized (gain) loss on derivative instruments, net |
( |
) | ||||||
Deferred income taxes |
||||||||
Changes in assets and liabilities: |
||||||||
Accounts receivable |
( |
) | ( |
) | ||||
Due from related parties |
||||||||
Due to related parties |
( |
) | ||||||
Prepaids obligations |
||||||||
Accounts payable |
( |
) | ||||||
Accrued liabilities |
( |
) | ( |
) | ||||
Right-of-use |
||||||||
Other long-term liabilities |
( |
) | ||||||
Net Cash Provided by Operating Activities |
||||||||
Cash Flows from Investing Activities: |
||||||||
Capital expenditures, including exploration expense |
( |
) | ( |
) | ||||
Proceeds from sale of properties and equipment |
||||||||
Net Cash Provided by (Used in) Investing Activities |
( |
) | ||||||
Cash Flows from Financing Activities: |
||||||||
Purchase of stock for treasury |
( |
) | ( |
) | ||||
Proceeds from long-term bank debt and other long-term obligations |
||||||||
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 |
||||||||
Cash and Cash Equivalents at the End of the Period |
$ | $ | ||||||
Supplemental Disclosures: |
||||||||
Income taxes paid |
$ | $ | ||||||
Interest paid |
$ | $ | ||||||
(Thousands of dollars) |
June 30, 2023 |
December 31, 2022 |
||||||
Accounts Receivable: |
||||||||
Joint interest billing |
$ | $ | ||||||
Trade receivables |
||||||||
Oil and gas sales |
||||||||
Other |
||||||||
Less: Allowance for doubtful accounts |
( |
) | ( |
) | ||||
Total |
$ | $ | ||||||
Accounts Payable: |
||||||||
Trade |
$ | $ | ||||||
Royalty and other owners |
||||||||
Partner advances |
||||||||
Other |
||||||||
Total |
$ | $ | ||||||
(Thousands of dollars) |
June 30, 2023 |
December 31, 2022 |
||||||
Accrued Liabilities: |
||||||||
Compensation and related expenses |
$ | $ | ||||||
Property costs |
||||||||
Taxes |
||||||||
Other |
||||||||
Total |
$ | $ | ||||||
(Thousands of dollars) |
Operating Leases |
|||
2023 |
$ | |||
2024 |
||||
2025 |
||||
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 |
||||
Non-current portion included in other long-term obligations |
$ | |||
(Thousands of dollars) |
June 30, 2023 |
|||
Asset retirement obligation at December 31, 2022 |
$ | |||
Additions |
||||
Liabilities settled |
( |
) | ||
Accretion of discount |
||||
Asset retirement obligation at June 30, 2023 |
$ | |||
Less current portion of asset retirement obligations |
||||
Asset retirement obligations, long-term |
$ | |||
June 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 June 30, 2023 |
||||||||||||
(Thousands of dollars) |
||||||||||||||||
Assets |
||||||||||||||||
Commodity derivative contracts |
$ |
— |
$ |
— |
$ |
$ |
||||||||||
Total assets |
$ |
— |
$ |
— |
$ |
$ |
||||||||||
Liabilities |
||||||||||||||||
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 |
||||||||||||
(Thousands of dollars) |
||||||||||||||||
Assets |
||||||||||||||||
Commodity derivative contracts |
$ |
— |
$ |
— |
$ |
$ |
||||||||||
Total assets |
$ |
— |
$ |
— |
$ |
$ |
||||||||||
Liabilities |
||||||||||||||||
Commodity derivative contracts |
$ |
— |
$ |
— |
$ |
( |
) |
$ |
( |
) | ||||||
Total liabilities |
$ |
— |
$ |
— |
$ |
( |
) |
$ |
( |
) | ||||||
(Thousands of dollars) |
||||
Net Liabilities – December 31, 2022 |
$ | ( |
) | |
Total realized and unrealized gains (losses): |
||||
in earnings (a) |
||||
Purchases, sales, issuances and settlements |
||||
Net Liabilities — June 30, 2023 |
$ | |||
| (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 |
||||||||||||
(Thousands of dollars) |
Balance Sheet Location |
June 30, 2023 |
December 31, 2022 |
|||||||||
Asset Derivatives: |
||||||||||||
Derivatives not designated as cash-flow hedging instruments: |
||||||||||||
Crude oil commodity contract |
Derivative asset | $ | $ | |||||||||
Natural gas commodity contract |
Derivative asset | |||||||||||
Total |
$ | $ | ||||||||||
Liability Derivatives: |
||||||||||||
Derivatives not designated as cash-flow hedging instruments: |
||||||||||||
Crude oil commodity contracts |
Derivative liability | $ | $ | ( |
) | |||||||
Natural gas commodity contracts |
Derivative liability | ( |
) | |||||||||
Total |
$ | $ | ( |
) | ||||||||
Total derivative instruments |
$ | $ | ( |
) | ||||||||
Amount of gain/loss recognized in income |
||||||||||
(Thousands of dollars) |
Location of gain/loss recognized in income |
2023 |
2022 |
|||||||
Derivatives not designated as cash-flow hedge instruments: |
||||||||||
Natural gas commodity contracts |
Unrealized gain (loss) on instruments, net |
( |
) | |||||||
Crude oil commodity contracts |
Unrealized gain (loss) on instruments, net |
( |
) | |||||||
Natural gas commodity contracts |
Realized gain (loss) on derivative instruments, net |
( |
) | |||||||
Crude oil commodity contracts |
Realized loss on derivative instruments, net | ( |
) | ( |
) | |||||
| $ | $ | ( |
) | |||||||
Six Months Ended June 30, |
||||||||||||||||||||||||
2023 |
2022 |
|||||||||||||||||||||||
Net Income (In 000’s) |
Weighted Average Number of Shares Outstanding |
Per Share Amount |
Net Income (In 000’s) |
Weighted Average Number of Shares Outstanding |
Per Share Amount |
|||||||||||||||||||
Basic |
$ | $ | $ | $ | ||||||||||||||||||||
Effect of dilutive securities: |
||||||||||||||||||||||||
Options |
— | — | ||||||||||||||||||||||
Diluted |
$ | $ | $ | $ | ||||||||||||||||||||
Three Months Ended June 30, |
||||||||||||||||||||||||
2023 |
2022 |
|||||||||||||||||||||||
Net Income (In 000’s) |
Weighted Average Number of Shares Outstanding |
Per Share Amount |
Net Income (In 000’s) |
Weighted Average Number of Shares Outstanding |
Per Share Amount |
|||||||||||||||||||
Basic |
$ | $ | $ | $ | ||||||||||||||||||||
Effect of dilutive securities: |
||||||||||||||||||||||||
Options |
— | — | ||||||||||||||||||||||
Diluted |
$ | $ | $ | $ | ||||||||||||||||||||
| 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. We also hold a 33.3% interest in a limited partnership that owns a 138,000-square-foot retail shopping center on ten acres in Prattville, Alabama. 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 balanced 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 and 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 and, consequently, 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 additional reserves of its leasehold acreage positions in Texas and Oklahoma. In the Permian Basin of West Texas and eastern New Mexico the Company maintains an acreage position of approximately 15,849 gross (9,236 net) acres, 97% of which is located in Reagan, Upton, Martin, and Midland counties of Texas where our current horizontal drilling activity is focused. We believe this acreage has significant resource potential in the Spraberry and Wolfcamp intervals for additional horizontal drilling that could support the drilling of as many as 250 additional horizontal wells. In Oklahoma we maintain
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an acreage position of approximately 46,960 gross (10,137 net) acres. Our Oklahoma horizontal development is focused primarily in Canadian, Kingfisher, Grady, and Garvin counties. We believe approximately 4,113 net acres in these counties hold significant 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 future development, our share of these future capital expenditures would be approximately $33 million at an average 10% ownership level.
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, San Miguel, Olmos, and Yegua formations at depths ranging from 3,000 to 12,500 feet. We had 150 producing wells (69 net) in the Gulf Coast region as of December 31, 2022, of which 89 wells are operated by us. Average net daily production in our Gulf Coast Region at year-end 2022 was 227 Boe. At December 31, 2022, we had 790 MBoe of proved reserves in the Gulf Coast region, which represented 4.7% of our total proved reserves. We maintain an acreage position of over 8,707 gross (1,215 net) acres in this region, primarily in Dimmit and Polk counties. We operate a field service group in this region from a field office in Carrizo Springs, Texas utilizing four workover rigs, twenty water transport trucks, two saltwater disposal wells, and several trucks and excavating equipment. Services, including well service support, site preparation and construction for drilling and workover operations, are provided to third-party operators as well as utilized for our own operated wells and locations. As of June 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. Average net daily production in our Mid-Continent Region in 2022 was 897 Boe. At December 31, 2022, we had 2,659 MBoe of proved reserves in the Mid-Continent area, representing 16% of our total proved reserves. We currently maintain an acreage position of approximately 47,120 gross (10,297 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 in various counties of Oklahoma reducing our future plugging liability without a significant change in value of our producing reserves.
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As of June 30, 2023, in the Mid-Continent region, the Company is participating with 1.96% interest in three 15,000’ long horizontal wells in Canadian County, Oklahoma operated by Ovintiv Mid-Continent Inc. All three wells were brought on production June 6th and are currently flowing. The expected reserves of these three wells were included in the 2022 year-end reserve report as proved undeveloped.
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. Average net daily production in Our West Texas Region at year-end 2022 was 3,257 Boe. At 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 15,849 gross (9,236 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 horizontal drilling in the Spraberry, Jo Mill, and Wolfcamp 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.
As of June 30, 2023, the Company was participating in the flowback of 15 two-mile-long horizontal wells in Reagan County, Texas brought on-line in the second quarter. The Company has 49.7% interest in five wells operated by Double Eagle and 25% interest in ten wells operated by Hibernia Energy. In Upton County, Texas, the Company was also participating with Apache in two 3-mile-long horizontals with 47.52% ownership. These two wells were cased after reaching TD and are being completed. In Martin County, Texas, the Company is participating with ConocoPhillips in the drilling of five 2.5-mile-long horizontals with 20.83% interest. These five wells are in the process of being completed and are expected to be on-line in late August. Combined, we expect to spend approximately $78 million in the drilling and completion of these 22 West Texas horizontals and their associated facilities. These 22 wells and their forecast reserves were included in the 2022 year-end reserve report as proved undeveloped. The 10 wells operated by Hibernia were placed on production in late April 2023 and based on the success of these wells Hibernia has indicated their intent to spud an additional 16 wells on adjacent acreage late in the fourth quarter of this year. These additional wells are slated to be in production in the first quarter of 2024. Our share of these 16 wells will be between 37.5% and 50% with an average of 41.1% and an investment of approximately $75 million. In addition, Double Eagle has notified us of their plans to drill six 10,000’ horizontal wells in Reagan County with spud dates in July and production start expected in the fourth quarter of 2023. These six wells are being drilled on an acreage block that is an extension to Double Eagle’s Hughes Alpine development described above and where the Company holds leasehold acreage giving us the right to participate for approximately 6.8% interest in these two-mile-long horizontals. Our share of the total investment in these wells will be approximately $3.5 million. The Company is also planning for participation in 12 additional wells operated by DE IV Operating, LLC (Double Eagle) in the Hughes Alpine area with spud dates as early as July, 2023. The Company will have 23% working interest in these additional 12 wells and invest approximately $26 million in the drilling, completion, and their facilities. These additional wells will increase our development budget to over $100 million in 2023.
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 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:
| 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) |
NGLs (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. |
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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 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.
At 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 successfully 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.
At 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 for the more than fifteen horizontal wells that we planned to participate in located primarily in West Texas.
In 2022, the Company participated in eight horizontal wells that were drilled and completed; 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 wells 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 operated by three different operators. In Martin County, we are participating with ConocoPhillips in five 2.5-mile-long horizontal wells in which the Company has 20.83% interest with a planned capital investment of $12.1 million. In Reagan County, we are participating with Hibernia Energy III in 10 two-mile horizontals with 25% interest and an expected investment of $25.6 million. Also in Reagan County, we are participating with Double Eagle (DE IV) in five two-mile-long horizontals with nearly 50% interest, carrying an expected net capital outlay of $23.4 million. All twenty of these West Texas wells are either producing or are in the process of being completed. All 10 of the wells drilled by Hibernia Energy III in the first quarter were put on production in late April 2023. The five active horizontal wells operated by Double Eagle were put on production in June of 2023. The remaining five wells with ConocoPhillips are in the process of being completed and expected to be on production in August of 2023.
In January of 2023, the Company joined Ovintiv USA, Inc. in the spudding of three 3-mile-long horizontal wells in Canadian County, Oklahoma with 1.96% interest and an expected investment of $645,000. These wells began production in early June.
In March of 2023, Apache Corporation spud two 3-mile-long horizontals in Upton County, Texas in which the Company has 49.4% interest with an expected total capital investment of $16.1 million. We anticipate completion of these two 15,000’ long horizontals to begin in July, and initial production to occur in the third quarter of 2023.
At December 31, 2022, the Company had 6,366 Mboe of proved undeveloped reserves attributable to the 25 horizontal wells described above. In total, the Company expects to invest $78 million in these 25 horizontal wells, all of which, as of July 15, 2023, have been drilled, with 20 fully completed, 18 of these on production and the remaining seven to be on production in the third quarter of 2023. Additional anticipated development mentioned in this report is not included in the 2022 year-end reserve report.
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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, are summarized as follows (in thousands of dollars):
| 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 extensive 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 lower initial production rates but with higher expected return on investment. We believe that with today’s technology, horizontal development of our reserves provides superior economic results as compared to vertical development, by 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 will 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 in Oklahoma and on track to drill and complete approximately 40 wells in 2023. The following is a description of recent, current, and expected near-term drilling activities.
In 2021, The Company participated for 47.5% interest with Apache Corporation in the drilling of nine two-mile-long horizontal wells in Upton County, Texas, and with Ovintiv Mid-Continent for 11.25% interest in four two-mile horizontal wells in Canadian County, Oklahoma. Twelve of these horizontal wells were completed and placed into production in the fourth quarter of 2021. One of the Ovintiv wells, however, had a casing leak issue and has been temporarily abandoned. The Company invested approximately $32 million in these thirteen wells.
In the first three quarters of 2022, the Company participated in eight horizontal wells. Four of these wells are located in Irion County, West Texas, operated by SEM Operating Company, and four are located in Canadian County, Oklahoma, operated by Ovintiv Mid-Continent, Inc. Our investment in these eight wells was approximately $4 million and all were brought on production in August of 2022.
In the fourth quarter of 2022, we began participation in the drilling of 20 horizontal wells located in West Texas operated by three different operators. In Martin County, we are participating with ConocoPhillips in five 2.5-mile-long horizontal wells in which the Company has 20.83% interest with a planned capital investment of $12.1 million. In Reagan County, we are participating with Hibernia Energy III in 10 two-mile horizontals with 25% interest and an expected investment of $25.6 million. Also in Reagan County, we are participating with Double Eagle (DE IV) in five two-mile-long horizontals with nearly 50% interest, carrying an expected net capital outlay of $23.4 million. Fifteen of these West Texas wells are producing and the remaining five are in the process of being completed. All 10 of the wells operated by Hibernia Energy III were put on production in late April 2023. The five wells operated by Double Eagle are also on production as of early June of 2023. The remaining five wells with ConocoPhillips are in the process of being completed and expected to be on production in August of 2023.
In January of 2023, the Company joined Ovintiv USA, Inc. in the spudding of three 3-mile-long horizontal wells in Canadian County, Oklahoma with 1.96% interest and an expected investment of $645,000. Production began June 6, 2023. In addition, in March of 2023, Apache Corporation spud two 3-mile-long horizontals in Upton County, Texas in which the Company has 49.4% interest with an expected total capital investment of $16.1 million. These two horizontals are cased and as of July 25 are waiting on a frac crew. We anticipate completion of these two 15,000’ long horizontals in July and initial production to occur in the third quarter of 2023.
In total, the Company expects to invest $78 million in these 25 horizontal wells in West Texas. In December 2022, we prepaid $32 million toward drilling costs, and the remaining $46 million in estimated drilling and completion expenses will be incurred in 2023.
We anticipate that success from the 22 horizontals in West Texas described above will lead to additional near-term horizontal drilling proposals across five leasehold blocks in three counties of West Texas: 26 additional 10,000’ long horizontals in Reagan County with Hibernia or Double Eagle, ten additional 12,500’ long horizontals in Martin County with ConocoPhillips, and six additional 15,000’ long horizontals in Upton County with Apache.
In addition to these anticipated 26 additional wells in West Texas, Hibernia has indicated their intent to drill 16 10,000’ long horizontal wells this year in Regan County with spud dates to occur late in the fourth quarter and production to begin in the second quarter of 2024. Our interest in these wells will be from 37.5% to 50% with an average of 41.18% and our investment will be approximately $75 million. In addition, Double Eagle has notified us of their plans to drill six 10,000’ horizontal wells in Reagan County with spud dates in July and production start expected in December 2023. These six wells will be drilled on an acreage block that is an extension to Double Eagle’s Hughes Alpine development described above and where the Company has leasehold acreage giving us the right to participate for approximately 6.8% interest in these two-mile-long horizontals. Our share of the investment in these wells will be approximately $4 million.
All 48 of the current and near-term drilling proposals described above will target pay intervals of the Wolfcamp and Spraberry formations and in total will require an estimated $200 million in net capital investment through 2024. We have also identified 27 horizontal locations that would be a natural progression of development for three of these project areas in Upton and Reagan counties. These 27 wells are anticipated to be drilled in the 2025-2026 timeframe and would require net investment of approximately $100 million. In total, with the $78 million current investment in 22 wells, the $200 million investment in 48 near-term wells in Upton and Reagan counties, the $100 million in 27 subsequent drill sites, and additional drilling not yet scheduled, we are expecting to invest approximately $400 million in horizontal development over the next several years.
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In the Permian Basin of West Texas and eastern New Mexico, we maintain an acreage position of approximately 15,849 gross (9,236 net) acres, 96.5% of which is located in Reagan, Upton, Martin, and Midland counties of Texas where our current West Texas horizontal drilling activities are focused. We believe this acreage has the resource potential to support the drilling of as many as 190 future horizontal wells following the active 22 and anticipated 42 horizontal wells described above.
In Oklahoma, we are focused on the development of our reserves in Canadian, Grady, Kingfisher, Garfield, Major, and Garvin counties where we have approximately 4,113 net leasehold acres in the Scoop/Stack Play. We are currently participating with Ovintiv in three 3-mile-long horizontals in Canadian County with 1.95% Of our 4,113 net leasehold acres, we believe 2,355 net acres hold significant additional resource potential that could support the drilling of as many as 46 new horizontal wells based on an estimate of four wells per multi-section drilling unit, two in the Mississippian and two in the Woodford Shale. In the near term, we anticipate nine new drilling proposals to be received with an estimated net expense of $5.2 million covering 338 net leasehold acres. Proposals may be received on the remaining 2,017 acres, however, rather than participate we may choose to sell the acreage or farm-out, receiving cash and retaining an over-riding royalty interest.
RESULTS OF OPERATIONS:
We reported net income of $11.5 million, or $6.14 per share and $10.1 million, or $5.35 per share for the six and three months ended June 30, 2023, respectively, as compared to $22.1 million, or $11.18 per share and $11 million, or $5.57 per share for the six and three months ended June 30, 2022, respectively. Current year net income reflects changes in production and commodity prices over the three and six months ended June 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.
Oil, gas and NGLs sales decreased $9.9 million, or 28.5% from $34.9 million for the three months ended June 30, 2022 to $25.0 million for the three months ended June 30, 2023, and $25.1 million, or 36.5% from $68.8 million for the six months ended June 30, 2022 to $43.7 million for the six months ended June 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 offset by the new wells placed in production during May and June of 2023.
The following tables summarizes the primary components of production volumes and average sales prices realized for the three and six months ended June 30, 2023 and 2022 (excluding realized gains and losses from derivatives).
| Six months ended June 30, | ||||||||||||||||
| 2023 | 2022 | Increase / (Decrease) |
Increase / (Decrease) |
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| Barrels of Oil Produced |
490,373 | 508,000 | (17,627 | ) | (3.5 | )% | ||||||||||
| Average Price Received |
$ | 72.49 | $ | 102.64 | $ | (30.15 | ) | (29.4 | )% | |||||||
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| Oil Revenue (In 000’s) |
$ | 35,546 | $ | 52,143 | $ | (16,597 | ) | (31.8 | )% | |||||||
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| Mcf of Gas Sold |
1,685,540 | 1,577,000 | 108,540 | 6.9 | % | |||||||||||
| Average Price Received |
$ | 1.77 | $ | 5.35 | $ | (3.58 | ) | (66.9 | )% | |||||||
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| Gas Revenue (In 000’s) |
$ | 2,980 | $ | 8,403 | $ | (5,423 | ) | (64.5 | )% | |||||||
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| Barrels of Natural Gas Liquids Sold |
251,484 | 210,000 | 41,484 | 19.8 | % | |||||||||||
| Average Price Received |
$ | 20.57 | $ | 39.40 | $ | (18.83 | ) | (47.8 | )% | |||||||
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| Natural Gas Liquids Revenue (In 000’s) |
$ | 5,174 | $ | 8,273 | $ | (3,099 | ) | (37.5 | )% | |||||||
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| Total Oil & Gas Revenue (In 000’s) |
$ | 43,700 | $ | 68,819 | $ | (25,119 | ) | (36.5 | )% | |||||||
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| Three months ended June 30, | ||||||||||||||||
| 2023 | 2022 | Increase / (Decrease) |
Increase / (Decrease) |
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| Barrels of Oil Produced |
297,022 | 235,000 | 62,022 | 26.4 | % | |||||||||||
| Average Price Received |
$ | 70.59 | $ | 109.95 | $ | (39.36 | ) | (3.58 | )% | |||||||
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| Oil Revenue (In 000’s) |
$ | 20,968 | $ | 25,838 | $ | (4,870 | ) | (18.8 | )% | |||||||
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| Mcf of Gas Sold |
884,456 | 800,000 | 84,456 | 10.6 | % | |||||||||||
| Average Price Received |
$ | 1.39 | $ | 5.86 | $ | (4.47 | ) | (76.3 | )% | |||||||
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| Gas Revenue (In 000’s) |
$ | 1,228 | $ | 4,657 | $ | (3,429 | ) | (73.6 | )% | |||||||
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| Barrels of Natural Gas Liquids Sold |
145,659 | 106,000 | 39,659 | 37.4 | % | |||||||||||
| Average Price Received |
$ | 19.09 | $ | 41.72 | $ | (22.63 | ) | (54.3 | )% | |||||||
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| Natural Gas Liquids Revenue (In 000’s) |
$ | 2,780 | $ | 4,422 | $ | (1,642 | ) | (37.1 | )% | |||||||
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| Total Oil & Gas Revenue (In 000’s) |
$ | 24,976 | $ | 34,917 | $ | (9,941 | ) | (28.5 | )% | |||||||
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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 six months ended June 2023 and 2022:
| Three Months Ended June 30, |
Six Months Ended June 30, |
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| 2023 | 2022 | 2023 | 2022 | |||||||||||||
| Oil derivatives – realized losses |
$ | — | $ | (4,522 | ) | $ | (590 | ) | $ | (7,721 | ) | |||||
| Oil derivatives – unrealized gains (losses) |
— | 1,951 | 769 | (3,240 | ) | |||||||||||
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| Total losses on oil derivatives |
$ | — | $ | (2,571 | ) | $ | 179 | $ | (10,961 | ) | ||||||
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| Natural gas derivatives – realized losses |
$ | — | $ | (1,366 | ) | $ | 24 | $ | (1,986 | ) | ||||||
| Natural gas derivatives – unrealized gains (losses) |
— | 982 | 211 | (966 | ) | |||||||||||
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| Total losses on natural gas derivatives |
$ | — | $ | (384 | ) | $ | 235 | $ | (2,952 | ) | ||||||
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| Total losses on oil and natural gas derivatives |
$ | — | $ | (2,955 | ) | $ | 414 | $ | (13,913 | ) | ||||||
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Prices received for the six months ended June 30, 2023 and 2022, respectively, including the impact of derivatives were:
| 2023 | 2022 | |||||||
| Oil Price |
$ | 71.28 | $ | 87.44 | ||||
| Gas Price |
$ | 1.78 | $ | 4.09 | ||||
| NGLS Price |
$ | 20.57 | $ | 39.40 | ||||
Oil and gas production expense increased $0.4 million, or 5.5% from $7.3 million for the three months ended June 30, 2022 to $7.7 million for the three months ended June 30, 2023, and decreased $0.6 million, or 4.3% from $13.9 million for the six months ended June 30, 2022 to $13.3 million for the six months ended June 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 $0.5 million, or 26.3% from $1.9 million for the three months ended June 30, 2022 to $1.4 million for the three months ended June 30, 2023, and decreased $0.2 million, or 4.9% from $4.1 million for the six months ended June 30, 2022 to $3.9 million for the six months ended June 30, 2023. These decreases reflect the changes in oil and gas revenues in the related periods.
Field service income increased $1.1 million or 31.4% from $3.5 million for the second quarter 2022 to $4.6 million for the second quarter 2023 and increased $1.6 million, or 24.6% from $6.5 million for the six months ended June 30, 2022 to $8.1 million for the six months ended June 30, 2023. Workover rig services, hot oil treatments, saltwater hauling and disposal represent the bulk of our field service operations. These changes reflect increases in equipment utilization and service rates during these periods.
Field service expense increased $0.1 million or 3.0% from $3.3 million for the second quarter 2022 to $3.4 million for the second quarter 2023 and increased $0.4 million, or 6.6% from $6.1 million for the six months ended June 30, 2022 to $6.5 million for the six months ended June 30, 2023. Field service expenses primarily consist of wages and vehicle operating expenses which have fluctuated during the three and six months ended June 30, 2023 compared with the same periods of 2022. These changes reflect increases in equipment utilization during these periods.
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Depreciation, depletion and amortization expense remained flat at $3.9 million for the six months ended 2022 and 2023 as expense related to the new wells placed on production were offset by a decrease in costs on existing properties. Expense increased $0.6 million, or 8.7% from $6.9 million for the second quarter 2022 to $7.5 million for the second quarter 2023. This increase reflects the expense related to the new wells placed on production in May and June 2023.
General and administrative expense decreased $3.7 million, or 40.7% from $9.1 million for the six months ended June 30, 2022 to $5.4 million for the six months ended June 30, 2023, and decreased $0.1 million, or 4.2% from $2.4 million for the three months ended June 30, 2022 to $2.3 million for the three months ended June 30, 2023. This decrease in 2023 is primarily due to decreased employee compensation and benefits.
Interest expense decreased from $100 thousand to $100 thousand for the second quarter 2023 from $200 thousand for the second quarter 2022, and decreased $200 thousand from $500 thousand for the six months ended June 30, 2022 to $300 thousand for the six months ended June 2023. This decrease reflects the increase in rates and lower current borrowings under our revolving credit agreement.
Income tax expense for the June 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.
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 six months ended June 30, 2023 was $41.9 million, compared to $42.3 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 August 14, 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.
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The Company has a stock repurchase program in place, spending under this program during the first six months of 2023 was $5.3 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 six 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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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) |
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| 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 | $ | 94.59 | 294,044 | ||||||||
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| Total/Average |
60,500 | $ | 87.95 | |||||||||
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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 June 30, 2023, a total of 3,705,956 shares have been repurchased under this program for $87,846,189 at an average price of $23.70 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
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| Item 6. | EXHIBITS |
The following exhibits are filed as a part of this report:
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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) | ||||||
| August 15, 2023 | /s/ Charles E. Drimal, Jr. | |||||
| (Date) | Charles E. Drimal, Jr. | |||||
| President | ||||||
| Principal Executive Officer | ||||||
| /s/ Beverly A. Cummings | ||||||
| August 15, 2023 | Beverly A. Cummings | |||||
| Executive Vice President | ||||||
| Principal Financial Officer | ||||||
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