| 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 | ☐ | |||
| ☒ | Smaller Reporting Company | |||||
| Emerging growth company | ||||||
PrimeEnergy Resources Corporation
Index to Form 10-Q
September 30, 2022
2
Item 1. |
FINANCIAL STATEMENTS |
September 30, 2022 |
December 31, 2021 |
|||||||
| ASSETS |
||||||||
| Current Assets |
||||||||
| Cash and cash equivalents |
$ | $ | ||||||
| Accounts receivable, net |
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| Prepaid obligations |
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| Other current assets |
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|||||
| Total Current Assets |
||||||||
| Property and Equipment |
||||||||
| Oil and gas properties at cost |
||||||||
| Less: Accumulated depletion and depreciation |
( |
) | ( |
) | ||||
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|||||
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| Field and office equipment at cost |
||||||||
| Less: Accumulated depreciation |
( |
) | ( |
) | ||||
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|||||
| Total Property and Equipment, Net |
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| Derivative asset long-term and other assets |
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|||||
| Total Assets |
$ | $ | ||||||
| |
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|
|||||
| LIABILITIES AND EQUITY |
||||||||
| Current Liabilities |
||||||||
| Accounts payable |
$ | $ | ||||||
| Accrued liabilities |
||||||||
| Due to related parties |
||||||||
| Current portion of asset retirement and other long-term obligations |
||||||||
| Derivative liability short-term |
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| |
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|
|||||
| Total Current Liabilities |
||||||||
| Long-Term Bank Debt |
||||||||
| Asset Retirement Obligations |
||||||||
| Derivative Liability Long-Term |
||||||||
| Deferred Income Taxes |
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| Other Long-Term Obligations |
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| |
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|
|||||
| Total Liabilities |
||||||||
| Commitments and Contingencies |
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| Equity |
||||||||
| Common stock, $ |
||||||||
| Additional paid-in capital |
||||||||
| Retained earnings |
||||||||
| Treasury stock, at cost; 2022: shares |
( |
) | ( |
) | ||||
| |
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|
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| Total Equity |
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| |
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|
|||||
| Total Liabilities and Equity |
$ | $ | ||||||
| |
|
|
|
|||||
Three Months Ended September 30, |
Nine Months Ended September 30, |
|||||||||||||||
2022 |
2021 |
2022 |
2021 |
|||||||||||||
| Revenues |
||||||||||||||||
| Oil sales |
$ | $ | $ | $ | ||||||||||||
| Natural gas sales |
||||||||||||||||
| Natural gas liquids sales |
||||||||||||||||
| Realized (loss) on derivative instruments, net |
( |
) | ( |
) | ( |
) | ( |
) | ||||||||
| Field service income |
||||||||||||||||
| Unrealized gain (loss) on derivative instruments, net |
( |
) | ( |
) | ||||||||||||
| Other income |
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| |
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| Total Revenues |
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| Costs and Expenses |
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| Lease operating expense |
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| Field service expense |
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| Depreciation, depletion, amortization and accretion on discounted liabilities |
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| General and administrative expense |
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| |
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| Total Costs and Expenses |
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| Gain on Sale and Exchange of Assets |
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| |
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|
|||||||||
| Income (Loss) from Operations |
( |
) | ( |
) | ||||||||||||
| Other Income (Expense) |
||||||||||||||||
| Interest Income |
||||||||||||||||
| Interest Expense |
( |
) | ( |
) | ( |
) | ( |
) | ||||||||
| |
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|
|||||||||
| Income (Loss) Before Income Taxes |
( |
) | ( |
) | ||||||||||||
| Income Taxes Expense (Benefit) |
( |
) | ( |
) | ||||||||||||
| |
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|
|||||||||
| Net Income (Loss) |
( |
) | ( |
) | ||||||||||||
| Less: Net Income Attributable to Non-Controlling Interests |
||||||||||||||||
| |
|
|
|
|
|
|
|
|||||||||
| Net Income (Loss) Attributable to PrimeEnergy |
$ | $ | ( |
) | $ | $ | ( |
) | ||||||||
| |
|
|
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|
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|
|
|||||||||
| Basic Income (Loss) Per Common Share |
$ | $ | ( |
) | $ | $ | ( |
) | ||||||||
| |
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|
|
|
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|
|||||||||
| Diluted Income (Loss) Per Common Share |
$ | $ | ( |
) | $ | $ | ( |
) | ||||||||
| |
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|
|||||||||
Common Stock |
||||||||||||||||||||||||||||||||
Shares |
Amount |
Additional Paid-In Capital |
Retained Earnings |
Treasury Stock |
Total Stockholders’ Equity – PrimeEnergy |
Non- Controlling Interest |
Total Equity |
|||||||||||||||||||||||||
| Balance at December 31, 2021 |
$ | $ | $ | $ | ( |
) | $ | $ | $ | |||||||||||||||||||||||
| Purchase |
( |
) | — | — | — | ( |
) | ( |
) | — | ( |
) | ||||||||||||||||||||
| Net Income |
— | — | — | — | ||||||||||||||||||||||||||||
| Balance at September 30, 2022 |
$ | $ | $ | $ | ( |
) | $ | $ | $ | |||||||||||||||||||||||
| |
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|
| Balance at December 31, 2020 |
$ | $ | $ | $ | ( |
) | $ | $ | $ | |||||||||||||||||||||||
| Net (Loss) Income |
( |
) | ( |
) | ( |
) | ||||||||||||||||||||||||||
| Purchase of non- controlling interest |
— | — | — | — | ( |
) | ( |
) | ||||||||||||||||||||||||
| |
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|
|
|
|
|
|
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|
|||||||||||||||||
| Balance at September 30, 2021 |
$ | $ | $ | $ | ( |
) | $ | $ | $ | |||||||||||||||||||||||
| |
|
|
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|
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|
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|
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|
|||||||||||||||||
2022 |
2021 |
|||||||
| Cash Flows from Operating Activities: |
||||||||
| Net Income (Loss) |
$ | $ | ( |
) | ||||
| Adjustments to reconcile net income (loss) to net cash provided by operating activities: |
||||||||
| Depreciation, depletion, amortization and accretion on discounted liabilities |
||||||||
| Gain on sale of properties |
( |
) | ( |
) | ||||
| Unrealized (gain) loss on derivative instruments, net |
( |
) | ||||||
| Provision for deferred income taxes |
( |
) | ||||||
| Changes in operating assets and liabilities: |
||||||||
| Accounts receivable |
( |
) | ( |
) | ||||
| Due to related parties |
( |
) | ||||||
| Other assets |
( |
) | ( |
) | ||||
| Accounts payable |
( |
) | ||||||
| Accrued liabilities |
||||||||
| |
|
|
|
|||||
| Net Cash Provided by Operating Activities |
||||||||
| |
|
|
|
|||||
| Cash Flows from Investing Activities: |
||||||||
| Capital expenditures |
( |
) | ( |
) | ||||
| Proceeds from sale of properties and equipment |
||||||||
| |
|
|
|
|||||
| Net Cash Provided by (Used in) Investing Activities |
( |
) | ||||||
| |
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|
|||||
| Cash Flows from Financing Activities: |
||||||||
| Purchase of stock for treasury |
( |
) | ||||||
| Purchase of non-controlling interests |
( |
) | ||||||
| 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 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) |
September 30, 2022 |
December 31, 2021 |
||||||
| 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) |
September 30, 2022 |
December 31, 2021 |
||||||
| Accrued Liabilities: |
||||||||
| Compensation and related expenses |
$ | $ | ||||||
| Property costs |
||||||||
| Taxes |
||||||||
| Other |
||||||||
| |
|
|
|
|||||
| Total |
$ | $ | ||||||
| |
|
|
|
|||||
| (Thousands of dollars) |
Operating Leases |
|||
| 2022 |
||||
| 2023 |
||||
| 2024 |
||||
| 2025 |
||||
| |
|
|||
| Total undiscounted lease payments |
$ | |||
| Less: Amount associated with discounting |
( |
) | ||
| |
|
|||
| Net operating lease liabilities |
$ | |||
| |
|
|||
(Thousands of dollars) |
September 30, 2022 |
|||
| Asset retirement obligation at December 31, 2021 |
$ | |||
| Liabilities incurred |
||||
| Liabilities settled |
( |
) | ||
| Accretion expense |
||||
| |
|
|||
| Asset retirement obligation at September 30, 2022 |
$ | |||
| |
|
|||
| September 30, 2022 |
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, 2022 |
||||||||||||
(Thousands of dollars) |
||||||||||||||||
| Assets |
||||||||||||||||
| Commodity derivative contracts |
$ | — | $ | — | $ | $ | ||||||||||
| |
|
|
|
|
|
|
|
|||||||||
| Total assets |
$ | — | $ | — | $ | $ | ||||||||||
| |
|
|
|
|
|
|
|
|||||||||
| Liabilities |
||||||||||||||||
| Commodity derivative contracts |
$ | — | $ | — | $ | ( |
) | $ | ( |
) | ||||||
| |
|
|
|
|
|
|
|
|||||||||
| Total liabilities |
$ | — | $ | — | $ | ( |
) | $ | ( |
) | ||||||
| |
|
|
|
|
|
|
|
|||||||||
| December 31, 2021 |
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, 2021 |
||||||||||||
(Thousands of dollars) |
||||||||||||||||
| Assets |
||||||||||||||||
| Commodity derivative contracts |
$ | — | $ | — | $ | $ | ||||||||||
| |
|
|
|
|
|
|
|
|||||||||
| Total assets |
$ | — | $ | — | $ | $ | ||||||||||
| |
|
|
|
|
|
|
|
|||||||||
| Liabilities |
||||||||||||||||
| |
|
|
|
|
|
|
|
|||||||||
| Total liabilities |
$ | — | $ | — | $ | ( |
) | $ | ( |
) | ||||||
| |
|
|
|
|
|
|
|
|||||||||
| (Thousands of dollars) |
||||
| Net Liabilities – December 31, 2021 |
$ | ( |
) | |
| Total realized and unrealized (gains) losses: |
||||
| Included in earnings (a) |
( |
) | ||
| Purchases, sales, issuances and settlements |
||||
| |
|
|||
| Net Liabilities - September 30, 2022 |
$ | ( |
) | |
| |
|
|||
| (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 |
September 30, 2022 |
December 31, 2021 |
|||||||
Asset Derivatives: |
||||||||||
Derivatives not designated as cash-flow hedging instruments: |
||||||||||
Crude oil commodity contracts |
Derivative asset short-term | $ | $ | — | ||||||
Total |
$ | $ | — | |||||||
Liability Derivatives: |
||||||||||
Derivatives not designated as cash-flow hedging instruments: |
||||||||||
Crude oil commodity contracts |
Derivative liability short-term | $ | ( |
) | $ | ( |
) | |||
Natural gas commodity contracts |
Derivative liability short-term | ( |
) | ( |
) | |||||
Crude oil commodity contracts |
Derivative liability long-term | — | ( |
) | ||||||
Natural gas commodity contracts |
Derivative liability long-term | — | ( |
) | ||||||
Total derivative instruments |
$ | ( |
) | $ | ( |
) | ||||
Total derivative instruments |
$ | ( |
) | $ | ( |
) | ||||
Amount of gain/loss recognized in income |
||||||||||
(Thousands of dollars) |
Location of gain/loss recognized in income |
2022 |
2021 |
|||||||
Derivatives not designated as cash-flow hedge instruments: |
||||||||||
Natural gas commodity contracts |
Unrealized (loss) on derivative instruments, net |
$ | ( |
) | $ | ( |
) | |||
Crude oil commodity contracts |
Unrealized gain (loss) on derivative instruments, net |
( |
) | |||||||
Natural gas commodity contracts |
Realized (loss) on derivative instruments, net |
( |
) | ( |
) | |||||
Crude oil commodity contracts |
Realized (loss) on derivative instruments, net |
( |
) | ( |
) | |||||
| $ | ( |
) | $ | ( |
) | |||||
Nine Months Ended September 30, |
||||||||||||||||||||||||
2022 |
2021 |
|||||||||||||||||||||||
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 |
|||||||||||||||||||
Basic |
$ | $ | $ | ( |
) | $ | ( |
) | ||||||||||||||||
Effect of dilutive securities: |
||||||||||||||||||||||||
Options (a) |
— | — | ||||||||||||||||||||||
Diluted |
$ | $ | $ | ( |
) | $ | ( |
) | ||||||||||||||||
Three Months Ended September 30, |
||||||||||||||||||||||||
2022 |
2021 |
|||||||||||||||||||||||
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 |
|||||||||||||||||||
Basic |
$ | $ | $ | ( |
) | $ | ( |
) | ||||||||||||||||
Effect of dilutive securities: |
||||||||||||||||||||||||
Options (a) |
— | — | — | — | — | |||||||||||||||||||
Diluted |
$ | $ | $ | ( |
) | $ | ( |
) | ||||||||||||||||
| (a) | The effect of the |
| 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 Condensed Consolidated Financial Statements and the accompanying Notes to the Condensed 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 presently own producing and non-producing properties located primarily in Texas, and Oklahoma. We also own a 12.5% overriding royalty interest in over 30,000 acres in the state of West Virginia. We are currently not receiving revenue from this asset, as development has not begun. In addition, we own well-servicing equipment and, through a wholly owned offshore company, a 60-mile-long pipeline offshore on the shallow shelf of Texas not currently in use. 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. 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, newer properties with development and exploration potential. We believe our balanced portfolio of 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 our 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 for exploration and development operations in areas in which we own interests. 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 through consistent growth and development of our oil and gas reserve base on a cost-effective basis.
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. We use derivative instruments to manage our commodity price risk. This practice may prevent us from receiving the full advantage of any 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. Since our derivative contracts are accounted for under mark-to-market accounting, we expect continued volatility in gains and losses on mark-to-market derivative contracts in our consolidated statement of operations as changes occur in the NYMEX price indices. Our existing derivative instruments expire 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 existing contracts are set to expire 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 NGL’s are higher than in the recent past, however, prices 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.
13
We are the operator of the majority of our developed and undeveloped acreage which is nearly all held by production. In the Permian Basin of West Texas and eastern New Mexico the Company maintains an acreage position of approximately 16,960 gross (10,640 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 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 an acreage position of approximately 47,120 gross (10,300 net) acres. Our Oklahoma horizontal development is focused primarily in Canadian, Kingfisher, Grady, and Garvin counties. We believe approximately 5,800 net acres in these counties hold significant additional resource potential that could support the drilling of as many as 50 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. Should we choose to participate with a working interest in future development, our share of these future capital expenditures would be approximately $34.6 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 availability of funds under our revolving credit facility.
District Information
The following table represents certain reserves and well information as of December 31, 2021.
| Proved Reserves as of December 31, 2021 (MBoe) | Gulf Coast |
Mid- Continent |
West Texas |
Other | Total | |||||||||||||||
| Developed |
906 | 2,383 | 8,957 | 6 | 12,252 | |||||||||||||||
| Undeveloped Total |
— | — | — | — | — | |||||||||||||||
| Average Net Daily Production (Boe per day) |
336 | 747 | 2,878 | 3 | 3,964 | |||||||||||||||
| Gross Productive Wells (Working Interest and ORRI Wells) |
207 | 549 | 576 | 200 | 1,532 | |||||||||||||||
| Gross Productive Wells (Working Interest Only) |
189 | 400 | 530 | 88 | 1,207 | |||||||||||||||
| Net Productive Wells (Working Interest Only) |
105 | 189 | 263 | 6 | 564 | |||||||||||||||
| Gross Operated Productive Wells |
137 | 195 | 321 | — | 653 | |||||||||||||||
| Gross Operated Water Disposal, Injection and Supply wells |
7 | 44 | 6 | — | 57 | |||||||||||||||
In several of our producing regions we have field service groups to service our operated wells and locations as well as third-party operators. These services consist of well service support, site preparation and construction services for drilling and workover operations. Our operations are performed utilizing workover or swab rigs, water transport trucks, saltwater disposal facilities, various land excavating equipment and trucks we own and that are operated by our field employees.
Gulf Coast Region
Our activities in the Gulf Coast region are primarily production and development of our existing operated properties 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. As of December 31, 2021, we had 207 producing wells (105 net) in the Gulf Coast region, of which 137 wells are operated by us. The Average net daily production in our Gulf Coast Region in 2021 was 336 Boe. At December 31, 2021, we had 906 MBoe of proved reserves in the Gulf Coast region, which represented 7% of our total proved reserves. We maintain an acreage position of over 10,700 gross (3,215 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-three water transport trucks, two saltwater disposal wells and several trucks and excavating equipment. 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. The Company also owns, through its wholly-owned offshore company, a 60-mile-long pipeline on the shallow shelf of Texas that is currently idle but may someday have value. As of September 30, 2022, 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, 2021, we had 549 producing wells (189 net) in the Mid-Continent area, of which 195 wells are operated by us. Principal producing intervals are in the Roberson, 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 2021 was 747 Boe. On December 31, 2021, we had 2,383 MBoe of proved reserves in the Mid-Continent area, representing 20% of our total proved reserves. We maintain an acreage position of approximately 47,120 gross (10,300 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 interests in several counties in the Stack and Scoop plays of Oklahoma where drilling primarily targets reservoirs of the Mississippian and Woodford formations.
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In the first half of 2022, in the Mid-Continent region, the Company participated with 9.38% interest in the drilling of four horizontal wells in Canadian County, Oklahoma operated by Ovintiv Mid-Continent Inc. All four wells have been completed and are online as of August 1st. The resulting production is an addition to our 2021 year-end proved producing reserve base. The Company divested of 354 non-strategic acres in Canadian County, year-to-date, with proceeds of $1.269 million.
West Texas Region
Our West Texas activities are concentrated in the Spraberry and Wolfcamp shale plays of the Permian Basin encompassing eight counties in West Texas. The oil produced from these shales is West Texas Intermediate Sweet and the gas is primarily casing-head gas with an average energy content of 1,400 Btu. The horizontal target depths range from 7,600 feet to 12,500 feet. This region is managed from our office in Midland, Texas.
As of December 31, 2021, we had 576 wells (263 net) in the West Texas area, of which 321 wells are operated by us. The average net daily production in Our West Texas Region in 2021 was 2,878 Boe. On December 31, 2021, we had 8,957 MBoe of proved reserves in the West Texas area, or 73% of our total proved reserves. We maintain an acreage position of approximately 16,960 gross (10,640 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, four hot oiler trucks, one kill truck, and two roustabout trucks. 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 for our operated wells and locations.
In the first half of 2022, the Company participated with 10.3% interest in the drilling of four 1.5-mile-long horizontal wells in Irion County, Texas operated by SEM Operating Company, LLC. All four wells have been drilled and completed and began production in early August.
In the fourth quarter of 2022, the Company completed an acreage exchange agreement with a large independent oil & gas operator to exchange approximately 725 net acres in the Midland Basin. In combination with existing acreage, this newly acquired acreage results in the Company having 100% working interest in approximately 1,200 contiguous acres and therefore the ability to efficiently and cost-effectively develop the Wolfcamp formation and other prospective reservoirs through 2-mile-long horizontal laterals.
Along with the 1,200 contiguous acres created from the acreage exchange, the Company has completed an agreement with a separate prominent independent oil & gas operator to create a 2,560-acre AMI for the joint development of horizontal wells. As part of the agreement, the Company has divested of a portion of its interest to operator for $16.1 million with the ability to acquire additional acreage from the operator located within the AMI. These exchanges should result in an approximately 50/50 ownership of the development with the operator. This newly formed 2,560 acreage-block will allow the Company to reinvest approximately $90 million of its cash flow in the drilling of as many as 18 new wells in a very promising area of the Wolfcamp and Spraberry horizontal trend.
In the fourth quarter of this year, we plan to participate with 20.8% interest in the drilling of five 2.5-mile-long horizontal wells in Martin County, Texas operated by ConocoPhillips, and to participate with 25% interest in the drilling of ten 2-mile-long horizontals in Reagan County, Texas with Hibernia Energy III, LLC. In the first quarter of 2023, BTA Oil Producers, LLC has indicated plans to drill nine 2.5-mile-long horizontals in Reagan County, Texas in which the Company will have an average 42 % interest. In addition, we plan to participate for 47% interest in two 3-mile-long horizontals with Apache Corporation in Upton County. In total, the Company will invest approximately $87 million in these 26 new wells with completions expected in the Spring of 2023 and all to be on production by mid-year 2023.
Reserve Information:
Our interests in proved developed and undeveloped oil and gas properties, including the interests held by the Partnerships, have been evaluated by Ryder Scott Company, L.P. for each of the three years ended December 31, 2021. 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
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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. See Part II, Item 8 “Financial Statements and Supplementary Data”, for additional discussions regarding proved reserves and their related cash flows. 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) |
||||||||||||||||||||||||||||||||||||
| 2019 | 4,381 | 2,914 | 19,995 | 10,628 | 1,833 | 1,017 | 4,547 | 3,608 | 6,214 | 3,931 | 24,542 | 14,235 | ||||||||||||||||||||||||||||||||||||
| 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 | ||||||||||||||||||||||||||||||||||||
| (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 2019, in West Texas, we participated in the initial three shallow horizontals on our Kashmir tract with one of each of these wells completed in the Wolfcamp “A”, Jo Mill, and Lower Spraberry. The Company has 48% interest in two of these wells and 5.3% in one well. All three wells were brought on production in May of 2019.
In 2020, in West Texas we participated in the drilling of seven wells: one for 8.6% interest which was brought into production in July of 2020, and six wells 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 reserve report. The Company invested approximately $8.0 million in these seven wells in 2020. Also in 2020, proved producing 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 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 2020. The Company has an average of 47.8% interest in these nine wells and invested approximately $30 million in these horizontal wells.
In our Oklahoma, Scoop-Stack play, in 2019, we participated in the drilling and completion of six wells on our WM Wallace tract for 7.67% interest, and nine wells, included on our Slash, Osborn, and Leon tracts, with an average 1.34% interest. In addition, three wells drilled in Oklahoma in 2018, were completed in 2019 converting 24 Mboe of reserves to proved developed. Also in Oklahoma, six wells designated as Shut-in on December 31, 2018, were brought into production in 2019: five located on our Ruthie tract, and one on our Braum tract.
In 2019, in our Gulf Coast region, we added production through the recompletion of three vertical wells in Polk County, Texas: one operated by the Company in which we have 72.5% interest, and two operated by Unit Petroleum in which the Company owns 2.81% working interest and 3.77% net revenue interest. In 2020, the Company successfully recompleted one additional operated well in the Segno field 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 reserves where the Company has an average 47.5% interest and invested approximately $30 million dollars in these wells. 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.
At December 31, 2021, the Company had 159 Mboe of proved developed shut-in reserves attributable to three horizontal wells drilled and completed in Canadian County, Oklahoma in December of 2021, but not yet online. Three of the four wells were successfully completed and online in January, 2022, while one well had completion issues and has been temporarily abandoned. Regarding the four drilled but uncompleted PUD wells in Grady County, Oklahoma noted in the paragraph above, reserves previously attributed to these wells were not included in the 2021 year-end reserve report as the operator has no near-term plans for their completion.
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During 2022, in our West Texas horizontal drilling program, we participated with 10.3% interest in the drilling of four horizontal wells with SEM Operating Company and have received proposals for an additional 24 horizontal wells, 15 of those to begin in the fourth quarter of this year. In total, the Company is likely to invest approximately $75 million in these 28 wells. In Oklahoma, thus far in 2022, the Company is participating for 9.38% interest with Ovintiv Mid-Continent in the drilling of four wells on our Bohlman tract in Canadian County, Oklahoma. These four wells and the four SEM wells in West Texas were placed in production during August of this year. In the first quarter of 2023, we intent to participate with Apache in the drilling of two 3-mile-long horizontals in Upton County, Texas and with BTA Oil Producers in the drilling of nine 2.5 mile-long horizontals in Reagan County, Texas. 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.
We employ technologies to establish proved reserves that have been demonstrated to provide consistent results capable of repetition. The technologies and economic data being used in the estimation of our proved reserves include, but are not limited to, electrical logs, radioactivity logs, geologic maps, production data, and well-test data. The estimated reserves of wells with sufficient production history are estimated using appropriate decline curves. Estimated reserves of producing wells with limited production history and for undeveloped locations are estimated using performance data from analogous wells in the area. These wells are considered analogous based on production performance from the same formation and with similar completion techniques.
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, 2021, 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 |
||||||||||||||||||||||||
| 2019 | $ | 116,592 | $ | 82,155 | $ | 42,700 | $ | 17,876 | $ | 159,292 | $ | 100,031 | $ | 18,419 | $ | 81,612 | ||||||||||||||||
| 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 | ||||||||||||||||
The PV 10 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. Our reserves include amounts attributable to non-controlling interests in the Partnerships. These interests represent less than 10% of our reserves.
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.
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Natural gas prices, based on the twelve-month average of the first of the month Henry Hub index price, were $3.598 per MMBtu in 2021 as compared to $1.985 per MMBtu in 2020, and $2.581 per MMBtu in 2019. Through November 1, 2022, the twelve-month average of the first of the month Henry Hub index price is $6.166 per MMBtu. Oil prices, based on the NYMEX first of the month average price, were $66.56 per barrel in 2021 as compared to $39.57 per barrel in 2020, and $55.69 per barrel in 2019. Through November 1, 2022, the NYMEX first of the month average price was $92.37. Since January 1, 2021, 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.
Maintaining a strong balance sheet and ample liquidity are key components of our business strategy. In 2022, 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.
In the third quarter of 2021, nine two-mile horizontal wells in Upton County, Texas, operated by Apache Corporation, were completed and brought into production. In the fourth quarter of 2021, three two-mile horizontal wells operated by Ovintiv Mid-Continent in Canadian County, Oklahoma were completed and brought online in January 2022. The Company has an average of 47.5% interest in the nine wells completed with Apache and 11.25% interest in the three wells completed with Ovintiv.
In the second quarter of 2022, the Company participated with SEM Operating Company LLC in the drilling of four 7,900’ horizontal wells in Irion County, Texas with 10.3% interest. These four wells began their production in August. Also in the second quarter of 2022, the Company participated in the drilling of four 10,000’-long horizontal wells in Canadian County, Oklahoma with 9.38% interest. These four wells, operated by Ovintiv Mid-Continent, were also put into production in early August of this year. In the fourth quarter of this year another fifteen wells are planned to be spud.
Since the start of our West Texas horizontal drilling program in 2015, we have participated in 81 wells and invested approximately $130 million in horizontal drilling in the Permian Basin. This includes the four wells currently in progress with SEM Operating Company in Irion County, Texas.
In Upton County, Texas, we are developing a contiguous 3,260-acre block with our joint venture partner, Apache Corporation. In this block the Company has 2,600 leasehold acres with interest between 14% and 56% depending on the particular lease and depth being developed. In 2018, eight successful wells were drilled horizontally by Apache Corporation in the Wolfcamp “B” of this block with the Company participating for 49% interest and this is believed to be full development of the Wolfcamp “B” reservoir. Together with Apache, we are planning development of the Upper Wolfcamp, Jo Mill, and Lower Spraberry reservoirs of this block. These shallower reservoirs have been proven-up on our offset 1,300-acre Kashmir tract. It is expected that as many as 36 additional horizontals will be developed on this 3,260-acres in the near future. This development is estimated to cost approximately $387.0 million, with the Company’s share being approximately $174.4 million. Two 3-mile-long horizontals have been slated for the first quarter of 2023. In addition to the 36 prospective wells to be drilled for these three reservoirs, a fourth target reservoir, the Middle Spraberry, is also prospective for future development. The potential of the Middle Spraberry on the 3,260-acre block is for 12 horizontal wells to be drilled and completed at a gross cost of approximately $138.0 million with the Company’s share being approximately $63.0 million. The actual number of wells that are eventually drilled as well as the cost and the timing of drilling will vary based upon many factors, including commodity market conditions.
In addition to the 3,260-acre block being developed, as described above, the Company has also been developing an offsetting 1,300-acre block in Upton County, Texas, with Apache Corporation as operator. In the second quarter of 2019 three horizontal wells were completed and brought on production from reservoirs above the Middle Wolfcamp: one in the Wolfcamp “A”, one in the Jo Mill, and one in the Lower Spraberry, confirming the economic viability of these reservoirs on our acreage. Prime holds 47.5% working interest in these reservoirs. As a result of the success of the initial three wells, nine additional horizontals followed and were completed in the third quarter of 2021. Our average 47.5% share of the cost of these nine horizontal wells was approximately $26.7 million in total. In addition to the Wolfcamp “A”, Jo Mill and Lower Spraberry, that are now considered fully developed on the tract, four locations in the Middle Spraberry will be considered for future development at an estimated gross cost of approximately $40.0 million with the Company’s share being approximately $18.8 million.
Also in the Permian Basin of West Texas, we are developing a 965-acre block with ConocoPhillips in Martin County, Texas. In 2016 and 2017, four horizontal wells were drilled, completed, and put on production. The Company owns 35% to 38% interest in this joint venture acreage where we have the potential to drill as many as 36 additional wells.
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As mentioned above, in West Texas, the Company participated for 10.3% interest with SEM Operating Company in four 7,900’-long horizontal wells in Irion County, Texas. We anticipate an investment of $2.55 million in these wells which have been producing since August. Also planned for this year is the drilling of ten 2-mile-long horizontals in Hibernia Energy, III, LLC, in Reagan County, Texas and the drilling of five 2.5-mile-long horizontal wells with ConocoPhillips in Martin County. The Company intends to participate for approximately 25% interest in the ten wells with Hibernia and for 20.8% interest in five wells with Conoco Phillips. Our expected investment in the drilling and completion of these wells is $36.3 million.
In the fourth quarter of 2022, the Company completed an acreage exchange agreement with a large independent oil & gas operator to exchange approximately 725 net acres in the Midland Basin. In combination with existing acreage, this newly acquired acreage results in the Company having 100% working interest in approximately 1,200 contiguous acres and therefore the ability to efficiently and cost-effectively develop the Wolfcamp formation and other prospective reservoirs through 2-mile-long horizontal laterals.
Along with the 1,200 contiguous acres created from the acreage exchange, the Company has completed an agreement with a separate prominent independent oil & gas operator to create a 2,560-acre AMI for the joint development of horizontal wells. As part of the agreement, the Company has divested of a portion of its interest to operator for $16.1 million with the ability to acquire additional acreage from the operator located within the AMI. These exchanges should result in an approximately 50/50 ownership of the development with the operator. This newly formed 2,560 acreage-block will allow the Company to reinvest approximately $90 million of its cash flow in the drilling of as many as 18 new wells in a very promising area of the Wolfcamp and Spraberry horizontal trend.
In Oklahoma, we are focused on the development of our reserves in Canadian, Grady, Kingfisher, Garfield, Major, and Garvin counties where we have approximately 5,800 net leasehold acres in the Scoop/Stack Play. In 2019, we participated for an average of 4.6% interest with Newfield Exploration in twelve successful wells in Canadian County on our Slash and Wallace tracts. In 2021, we participated for 11.25% interest with Ovintiv Mid-Continent Inc. in four wells on our Peters tract, in Canadian County. Three of these wells were successfully completed in December 2021 and online in January 2022, while one well had completion issues and has been temporarily abandoned. At today’s product prices, payout of the Company’s $2.3 million investment in these four wells occurred in four months.
In April 2022, in Oklahoma, the Company and Ovintiv Mid-Continent began drilling four horizontal wells on our Bohlman tract in the same area as the successful Peters wells. All four of the Bohlman wells have been drilled, completed, and were placed on production in early August.. The Company is participating with 9.38% interest in these wells with an approximate investment $2.45 million. In May, we sold 241 acres in Canadian County, Oklahoma for proceeds of $845,000, and in August another 113 acres for $423,700. Both of these sales were of non-strategic acreage and the Company retained its interest in existing wells and a small overriding royalty interest in future development.
We believe our 5,800 net leasehold acres in Oklahoma have the resource potential to support the drilling of as many as 50 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. Should we choose to participate in future development, our share of the capital expenditures would be approximately 34.6 million at a 10% ownership level; the Company will otherwise sell its rights for cash or cash plus a royalty or working interest.
LIQUIDITY AND CAPITAL RESOURCES
Maintaining a strong balance sheet and ample liquidity are key components of our business strategy. For 2022, we will continue our focus on preserving financial flexibility and ample liquidity as we manage the risks facing our industry. Our 2022 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 nine months ended September 30, 2022 was $47.3 million, compared to $18.8 million in the prior period.
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.
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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. Accordingly, the Company has in place the following swap agreements for oil and natural gas.
| 2022 | 2023 | 2022 | 2023 | |||||||||||||
| Swap Agreements |
||||||||||||||||
| Natural Gas (MMBTU) |
279,000 | 254,000 | $ | $ | 3.60 | |||||||||||
| Oil (barrels) |
79,300 | 70,700 | $ | $ | 69.50 | |||||||||||
In the first quarter of 2022, the Company participated in the drilling of four wells with SEM Operating Company in Irion County, Texas for 10.3% interest and in April of this year began participating with Ovintiv Mid-Continent in four wells in Canadian County, Oklahoma with 9.38% interest.
These eight wells have been completed and were put on production in early August. In addition, the Company has received drilling proposals for an additional 26 horizontal wells to be drilled in West Texas with 15 of these slated to begin drilling this year. In total, the Company is likely to invest approximately $86 million in these 26 wells. 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 $75 million. As of August 15, 2022, 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 2022. 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.
In the first quarter of 2022, the Company sold 1,809 net leasehold acres in Reagan and Midland Counties, Texas through three transactions receiving gross proceeds of $14.1 million and retaining certain over-riding royalty interests.
In the second quarter of 2022, the Company sold 241 net acres in Canadian County, Oklahoma for proceeds of $845,000 and a retained over-riding royalty interest.
In the third quarter of 2022, the Company sold an additional 113 net acres in Canadian County, Oklahoma for $423,700.
In November of 2022, the Company completed an acreage exchange with a large independent oil & gas operator to exchange approximately 725 net acres in the Midland Basin. When combined with currently held acreage, this acreage exchange results in the Company having 100% working interest in approximately 1,200 contiguous acres and therefore the ability to efficiently and cost-effectively develop the Wolfcamp and other prospective reservoirs through 2-mile-long horizontal laterals. In addition to this exchange, the Company has completed an agreement with a separate prominent independent oil & gas operator to create a 2,560-acre AMI for the joint development of horizontal wells. As part of the plan, the Company has divested a portion of its interest to the operator for $16.1 million and has the right to acquire additional acreage from the operator within the AMI. These exchanges should result in an approximate 50/50 ownership of the AMI development with the operator. This newly formed 2,560 acreage block will allow the Company to reinvest approximately $90 million of its cash flow in the drilling of as many as 18 new wells in a very promising area of the Wolfcamp and Spraberry horizontal trend.
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 2022 was $5.0 million. The Company expects continued spending under the stock repurchase program in 2022.
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RESULTS OF OPERATIONS
2022 and 2021 Compared
We reported net income of $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, as compared to net losses of $1.2 million, or $(0.58) per share and $5.0 million, or $(2.52) per share for the three and nine months ended September 30, 2021, respectively. Current year net income reflects increases in production and commodity price increases 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.
Oil, gas and NGLs sales increased $15.9 million, or 87.8% from $18.1 million for the three months ended September 30, 2021 to $34.0 million for the three months ended September 30, 2022, and $56.7 million, or 122.9% from $46.1 million for the nine months ended September 30, 2021 to $102.8 million for the nine months ended September 30, 2022
The following tables summarizes the primary components of production volumes and average sales prices realized for the three and nine months ended September 30, 2022 and 2021 (excluding realized gains and losses from derivatives).
| Nine months ended September 30, | ||||||||||||||||
| 2022 | 2021 | Increase / (Decrease) |
Increase / (Decrease) |
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| Barrels of Oil Produced |
752,500 | 480,000 | 272,500 | 56.8 | % | |||||||||||
| Average Price Received |
$ | 100.39 | $ | 63.28 | $ | 37.11 | 58.6 | % | ||||||||
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| Oil Revenue (In 000’s) |
$ | 75,546 | $ | 30,376 | $ | 45,170.00 | 148.7 | % | ||||||||
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| Mcf of Gas Sold |
2,456,800 | 2,395,000 | 61,800 | 2.6 | % | |||||||||||
| Average Price Received |
$ | 6.01 | $ | 3.32 | $ | 2.69 | 81.0 | % | ||||||||
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| Gas Revenue (In 000’s) |
$ | 14,762 | $ | 7,948 | $ | 6,814.00 | 85.7 | % | ||||||||
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| Barrels of Natural Gas Liquids Sold |
332,400 | 298,000 | 34,400 | 11.5 | % | |||||||||||
| Average Price Received |
$ | 37.54 | $ | 26.11 | $ | 11.43 | 43.8 | % | ||||||||
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| Natural Gas Liquids Revenue (In 000’s) |
$ | 12,477 | $ | 7,781 | $ | 4,696 | 60.4 | % | ||||||||
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| Total Oil & Gas Revenue (In 000’s) |
$ | 102,785 | $ | 46,105 | $ | 56,680 | 122.9 | % | ||||||||
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| Three months ended September 30, | ||||||||||||||||
| 2022 | 2021 | Increase / (Decrease) |
Increase / (Decrease) |
|||||||||||||
| Barrels of Oil Produced |
244,500 | 152,000 | 92.500 | 60.9 | % | |||||||||||
| Average Price Received |
$ | 95.72 | $ | 68.70 | $ | 27.02 | 39.3 | % | ||||||||
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| Oil Revenue (In 000’s) |
$ | 23,403 | $ | 10.442 | $ | 12,961 | 124.1 | % | ||||||||
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| Mcf of Gas Sold |
879,800 | 950,000 | (70,200 | ) | (7.39 | )% | ||||||||||
| Average Price Received |
$ | 7.23 | $ | 4.21 | $ | 3.02 | 71.7 | % | ||||||||
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| Gas Revenue (In 000’s) |
$ | 6,359 | $ | 3,998 | $ | 2,361 | 59.1 | % | ||||||||
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| Barrels of Natural Gas Liquids Sold |
122,400 | 103,000 | 19,400 | 18.8 | % | |||||||||||
| Average Price Received |
$ | 34.35 | $ | 35.26 | $ | (0.91 | ) | (2.59 | )% | |||||||
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| Natural Gas Liquids Revenue (In 000’s) |
$ | 4,204 | $ | 3,632 | $ | 572 | 15.7 | % | ||||||||
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| Total Oil & Gas Revenue (In 000’s) |
$ | 33,966 | $ | 18,072 | $ | 15,894 | 87.9 | % | ||||||||
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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 condensed consolidated statements of operations. As oil and natural gas prices remain volatile, mark-to-market accounting treatment creates volatility in our revenues.
Field service income increased $1.4 million or 58.3% from $2.4 million for the third quarter 2021 to $3.8 million for the third quarter 2022 and increased $4.6 million, or 74.2% from $6.2 million for the nine months ended September 30, 2021 to $10.8 million for the nine months ended September 30, 2022. These changes reflect the increase in utilization and rates resulting from the oil and gas price increases during these periods. Workover rig services, hot oil treatments, saltwater hauling and disposal represent the bulk of our field service operations.
21
Lease operating expense increased $2.3 million or 35.9% from $6.4 million for the third quarter 2021 to $8.7 million for the third quarter 2022 and increased $11.3 million or 73.9% from $15.3 million for the nine months ended September 30, 2021 to $26.6 million for the nine months ended September 30, 2022. This increase is primarily due to higher production taxes related to higher commodity prices during 2022 combined with workover expenses and lease operating expense related to higher lifting cost properties returned to production as commodity prices increased.
Field service expense increased $0.1 million or 3.4% from $2.9 million for the third quarter 2021 to $3.0 million for the third quarter 2022 and increased $3.3 million, or 53.2% from $6.2 million for the nine months ended September 30, 2021 to $9.5 million for the nine months ended September 30, 2022. Field service expenses primarily consist of wages and vehicle operating expenses which have fluctuated during the three and nine months ended September 30, 2022 compared with the same periods of 2021. These changes reflect the increase in utilization resulting from the oil and gas price increases during these periods.
Depreciation, depletion, amortization and accretion on discounted liabilities increased $0.8 million, or 11.6% from $6.9 million for the third quarter 2021 to $7.7 million for the third quarter 2022 and $1.9 million, or 9.5% from $20.0 million for the nine months ended September 30, 2021 to $21.9 million for the nine months ended September 30, 2022. These increases reflect the change in the property basis combined with production increases in 2022.
General and administrative expense increased $5.3 million, or 85.5% from $6.2 million for the nine months ended September 30, 2021 to $11.5 million for the nine months ended September 30, 2022, and increased $0.5 million, or 25.0% from $2.0 million for the three months ended September 30, 2021 to $2.5 million for the three months ended September 30, 2022. This increase in 2022 is primarily due to increased employee compensation and benefits.
Interest expense decreased from $0.5 million for the third quarter 2021 to $0.3 million for the third quarter 2022 and from $1.5 million for the nine months ended September 30, 2021 to $0.8 million for the nine months ended September 30, 2022. This decrease reflects the increase in rates and reduced borrowings under our revolving credit agreement.
Income tax benefit/expense for the September 30, 2022 and 2021 periods varied due to the change in net income or loss for those periods.
| 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 2022 that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.
22
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.
During the nine months ended September 30, 2022, the Company purchased the following shares of common stock as treasury shares.
| 2022 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 |
2,981 | $ | 76.21 | 144,740 | ||||||||
| February |
5,948 | $ | 73.26 | 138,792 | ||||||||
| March |
2,259 | $ | 75.36 | 136,533 | ||||||||
| April |
3,426 | $ | 74.82 | 133,107 | ||||||||
| May |
5,963 | $ | 82.37 | 127,144 | ||||||||
| June |
18,855 | $ | 85.18 | 108,289 | ||||||||
| July |
15,645 | $ | 79.68 | 92,644 | ||||||||
| August |
5,500 | $ | 87.99 | 87,144 | ||||||||
| September |
800 | $ | 92.80 | 86,344 | ||||||||
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| Total/Average |
61,377 | $ | 81,33 | |||||||||
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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 and June 13, 2018, the Board of Directors of the Company approved an additional 500,000 and 200,000 shares respectively, of the Company’s stock to be included in the stock repurchase program. A total of 3,700,000 shares have been authorized, to date, under this program. Through September 30, 2022, a total of 3,615,756 shares have been repurchased under this program for $78,266,619 at an average price of $22,15 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 |
Non
23
| Item 6. | EXHIBITS |
The following exhibits are filed as a part of this report:
24
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
| PRIMEENERGY RESOURCES CORPORATION | ||||||
| Dated: November 21, 2022 | By: | /s/ Charles E. Drimal, Jr. | ||||
| Charles E. Drimal, Jr. | ||||||
| Chairman, President | ||||||
25