PRIMEENERGY RESOURCES CORP (PNRG) FY 2024 MD&A
This page reproduces the company's own Item 7 MD&A text from the linked SEC filing. It is filer text, not grepcent analysis, scoring, or investment advice.
Item 7. 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 contains additional information that should be referred to when reviewing this material. Our subsidiaries are listed in Note 1 to the Consolidated Financial Statements.
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. In addition, we own a substantial amount of well servicing equipment. 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 and our ongoing hedging program position 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 and our credit facility.
We attempt to assume the position of operator in all acquisitions of producing properties and will continue to evaluate prospects for leasehold acquisitions and for exploration and development operations in areas in which we own interests. We continue to actively pursue the acquisition of producing properties. To diversify and broaden our asset base, we will consider acquiring the assets or stock in other entities and companies in the oil and gas business. Our main objective in making any such acquisitions will be to acquire income producing assets to build stockholder value through consistent growth in our oil and gas reserve base on a cost-efficient 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 all 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.
Market Conditions and Commodity Prices:
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. 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 have been volatile in recent years and consequently cannot determine with any degree of certainty what effect increases or decreases in these prices will have on our capital program, production volumes or revenues.
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Critical Accounting Estimates:
Proved Oil and Gas Reserves
Proved oil and gas reserves directly impact financial accounting estimates, including depreciation, depletion and amortization. Proved reserves represent estimated quantities of natural gas, crude oil, condensate, and natural gas liquids that geological and engineering data demonstrate, with reasonable certainty, to be recoverable in future years from known reservoirs under economic and operating conditions existing at the time the estimates were made. The process of estimating quantities of proved oil and gas reserves is very complex, requiring significant subjective decisions in the evaluation of all available geological, engineering and economic data for each reservoir. The data for a given reservoir may also change substantially over time as a result of numerous factors including, but not limited to, additional development activity, evolving production history and continual reassessment of the viability of production under varying economic conditions. Consequently, material revisions (upward or downward) to existing reserve estimates may occur from time to time.
Depreciation, Depletion and Amortization for Oil and Gas Properties
The quantities of estimated proved oil and gas reserves are a significant component of our calculation of depletion expense and revisions in such estimates may alter the rate of future expense. Holding all other factors constant, if reserves were revised upward or downward, earnings would increase or decrease respectively. Depreciation, depletion and amortization of the cost of proved oil and gas properties are calculated using the unit-of-production method. The reserve base used to calculate depletion, depreciation or amortization is the sum of proved developed reserves and proved undeveloped reserves for leasehold acquisition costs and the cost to acquire proved properties. The reserve base includes only proved developed reserves for lease and well equipment costs, which include development costs and successful exploration drilling costs. Estimated future dismantlement, restoration and abandonment costs, net of salvage values, are taken into account.
Asset Retirement Obligation (ARO):
The Company has significant obligations to remove tangible equipment and restore land at the end of oil and gas production operations. The Company’s removal and restoration obligations are primarily associated with plugging and abandoning wells. Estimating the future restoration and removal costs is difficult and requires management to make estimates and judgments. Asset removal technologies and costs are constantly changing, as are regulatory, political, environmental, safety, and public relations considerations. ARO associated with retiring tangible long-lived assets is recognized as a liability in the period in which the legal obligation is incurred and becomes determinable. The liability is offset by a corresponding increase in the underlying asset. The ARO liability reflects the estimated present value of the amount of dismantlement, removal, site reclamation, and similar activities associated with the Company’s oil and gas properties. The Company utilizes current retirement costs to estimate the expected cash outflows for retirement obligations. Inherent in the present value calculation are numerous assumptions and judgments including the ultimate settlement amounts, inflation factors, credit-adjusted discount rates, timing of settlement, and changes in the legal, regulatory, environmental, and political environments. Accretion expense is recognized over time as the discounted liability is accreted to its expected settlement value
Liquidity and Capital Resources:
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, and available capacity under our revolving credit facility.
Net cash provided by operating activities for the year ended December 31, 2024, was $115.9 million compared to $109.0 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.
If our exploratory drilling results in significant new discoveries, we will have to expend additional capital to finance the completion, development, and potential additional opportunities generated by our success. We believe that, because of the additional reserves resulting from the successful wells and our record of reserve growth in recent years, we will be able to access sufficient additional capital through bank financing.
Maintaining a strong balance sheet and ample liquidity are key components of our business strategy. For 2025, we will continue our focus on preserving financial flexibility and liquidity as we manage the risks facing our industry. Our 2025 capital budget is reflective of commodity prices and has been established based on an expectation of available cash flows, with any cash flow deficiencies expected to be funded by borrowings under our revolving credit facility. As we have done historically to preserve or enhance liquidity, we may adjust our capital program throughout the year, divest assets, or enter into strategic joint ventures.
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The Company maintains a Credit Agreement with a maturity date of December 20, 2028, providing for a credit facility totaling $300 million, with a borrowing base of $115 million. As of April 8, 2025, the Company had $17.5 million in outstanding borrowings and $97.5 million in availability under this facility. The bank reviews the borrowing base semi-annually and, at its 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 June 2025. 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.
Our credit agreement requires us to hedge a portion of our production as forecasted for the PDP reserves included in our borrowing base review engineering reports. The credit agreement requires that as of the last day of any fiscal quarter, if the borrowing base utilization percentage on such a date is less than 15%, then the borrower shall not be required to enter into any swap agreements. As of the quarter ended December 31, 2024, the Company had $4 million in outstanding borrowings and $111 million in availability. Accordingly, the Company had no swap agreements in place for oil and natural gas.
Development and Other Activities
The Company’s activities include development and exploratory drilling. Our strategy is to develop a balanced portfolio of drilling prospects that includes lower-risk wells with a high probability of success and higher-risk wells with greater economic potential. Horizontal development of our resource base provides superior returns relative to vertical development due to the ability of each horizontal wellbore to come in contact with a greater volume of reservoir rock across a greater distance, more efficiently draining the reserves with less infrastructure and thus at a lower cost per acre.
In 2024, the Company invested $113 million in 48 horizontals in West Texas: 47 of these are located in Reagan County and one is located in Upton County. In Reagan County, the Company joined Double Eagle in drilling and completing 33 new horizontal wells: on the “Honey RF” tract we completed 12 horizontals each being two-mile-long laterals, and participated with 50% interest investing $37 million; on the “Prime West” tract we have 50% interest in six wells and invested $20.5 million; on both the “Kramer” and “O’Bannion” tracts we participated in six horizontals, each with an average 8.3% interest and we invested approximately $7.8 million; and on the “Pink Floyd” tract we have less than 1% interest in two wells in which we invested approximately $174,900; and on our“Studley AV” tract we participated with Double eagle in testing the Wolfcamp “D” interval; in this well we have about 6.3% interest and invested approximately $600,000. Also in Reagan County, we participated with Civitas in 14 horizontal wells on the “Christi” tract, carrying an average of 39% interest and investing roughly $46.7 million. Also in 2024, in Upton County, we participated with Pioneer Natural Resources in one 2-mile-long horizontal with 3.94% interest, investing approximately $425,700. Of these 48 wells, 32 are 2-mile-long laterals, 14 are 2.5-mile-long laterals, and two are 3-mile-long laterals.
In addition to this activity, in June of 2024, we began participation with Apache in the drilling of six additional 3-mile-long laterals in Upton County on our “Mt. Moran” tract. Three of these wells were completed in late December 2024 and three were completed in January of 2025. All six new “Mt. Moran” wells are producing as of April 1, 2025. In these six Mt. Moran wells, the Company has an average of 51.16% interest and will in total invest approximately $40.5 million. In addition, in November of 2024, in Reagan County, we began participating with Double Eagle in 15 “OG” horizontal wells: eight are 2.5-mile-long laterals, and seven are 2-mile-long laterals. In each of these 15 “OG” wells the Company has approximately 23% interest and in total will invest roughly $29 million through completion of production facilities. These 15 horizontals are expected to be on production in mid to late April 2025. By the end of the second quarter of 2025, therefore, the Company will have invested approximately $70 million in these additional 21 horizontal wells.
In early March 2025, Ovintiv Mid-Continent spud two “Jennifer 1407” wells in Canadian County, Oklahoma; in these, we will participate for approximately 3.125% interest and invest $408,000. In the second and third quarters of 2025, we are anticipating the start of twenty new horizontals in the Midland Basin of West Texas: 15 wells operated by Double Eagle on our “Full House” tract in Reagan County in which the Company will participate with approximately 31% interest and invest $48.4 million, and five wells operated by ConocoPhillips on our “Schenecker” tract in Martin, County in which we plan to participate for 20.83% interest and invest $11.3 million. In total in these 22 wells, we will invest approximately $60 million.
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During 2024, to supplement cash flow and finance our future drilling programs, the Company sold 120 net mineral acres and 10 surface acres in Midland and Ector counties, Texas. For these, we received $1,386,000 in gross proceeds. In addition, we divested 37 producing and two saltwater injection wells in various counties of New Mexico and Texas. These divestments have extinguished a substantial amount in future plugging liability. Also in 2024, we sold our South Texas oil field services company, Eastern Oil Well Service, for proceeds of $2.8 million. Included with this sale were extensive oil field service equipment and transport trucks, as well as two commercial saltwater disposal wells. Acquisitions in 2024, entailed the purchase of 381 net leasehold acres in West Texas for approximately $3.9 million.
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 in 2024 and 2023 was $13.4 million and $7.5 million, respectively. The Company expects continued spending under the stock repurchase program in 2025.
Results of Operations
2024 and 2023 Compared
We reported a net income of $55.4 million for 2024, or $31.43 per share, compared to $28.1 million, or $15.19 per share for 2023. The current year net income reflects production increases offset by commodity price decreases. The significant components of income and expense are discussed below.
Oil, NGL and gas sales increased $115 million, or 107.01% to $223.1 million for the year ended December 31, 2024 from $107.7 million for the year ended December 31, 2023. Crude oil, NGL and natural gas sales vary due to changes in volumes of production sold and realized commodity prices. Our realized prices at the well head decreased an average of $1.04 per barrel, or 1.35% on crude oil, increased an average of $0.61 per barrel, or 3.11% on NGL and decreased $1.49 per Mcf, or 77.6% on natural gas during 2024 as compared to 2023.
Our crude oil production increased by 1,412,000 barrels, or 123.43% to 2,556,000 barrels for the year ended December 31, 2024 from 1,144,000 barrels for the year ended December 31, 2023. Our NGL production increased by 678,000 or 111.88% to 1,284,000 for the year ended December 31, 2024 from 606,000 barrels for the year ended December 31, 2023. Our natural gas production increased by 3,639 MMcf, or 88.18% 7,766 MMcf for the year ended December 31, 2024 from 4,127 MMcf for the year ended December 31, 2023. The changes in crude oil, NGL and natural gas production volumes are a result of new wells placed in production offset by the natural decline of existing properties.
The following table summarizes the primary components of production volumes and average sales prices realized for the years ended December 31, 2024 and 2023 (excluding realized gains and losses from derivatives).
| Years ended December 31, | Increase / | Increase / | ||||||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| 2024 | 2023 | (Decrease) | (Decrease) | |||||||||||||
| Barrels of Oil Produced | 2,556,000 | 1,144,000 | 1,412,000 | 123.43 | % | |||||||||||
| Average Price Received | $ | 75.80 | $ | 76.84 | $ | (1.04 | ) | (1.35 | )% | |||||||
| Oil Revenue (In 000’s) | $ | 193,737 | $ | 87,906 | $ | 105,831 | 120.39 | % | ||||||||
| Mcf of Gas Sold | 7,766,000 | 4,127,000 | 3,639,000 | 88.18 | % | |||||||||||
| Average Price Received | $ | 0.43 | $ | 1.92 | $ | (1.49 | ) | (77.60 | )% | |||||||
| Gas Revenue (In 000’s) | $ | 3,309 | $ | 7,935 | $ | (4,626 | ) | (58.30 | )% | |||||||
| Barrels of Natural Gas Liquids Sold | 1,284,000 | 606,000 | 678,000 | 111.88 | % | |||||||||||
| Average Price Received | $ | 20.25 | $ | 19.64 | $ | 0.61 | 3.11 | % | ||||||||
| Natural Gas Liquids Revenue (In 000’s) | $ | 25,996 | $ | 11,901 | $ | 14,095 | 118.44 | % | ||||||||
| Total Oil & Gas Revenue (In 000’s) | $ | 223,042 | $ | 107,742 | $ | 115,300 | 107.01 | % |
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.
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The following table summarizes the results of our derivative instruments for the years ended December 2024 and 2023:
| Years ended December 31, | |||||||
|---|---|---|---|---|---|---|---|
| 2024 | 2023 | ||||||
| Oil derivatives - realized gains (losses) | $ | 0 | $ | 179 | |||
| Oil derivatives – unrealized gains | 0 | -- | |||||
| Total gains (losses) on oil derivatives | $ | 0 | $ | 179 | |||
| Natural gas derivatives – realized gains (losses) | 0 | 235 | |||||
| Natural gas derivatives – unrealized gains | 0 | -- | |||||
| Total gains (losses) on natural gas derivatives | $ | 0 | $ | 235 | |||
| Total gains (losses) on oil and natural gas | $ | 0 | $ | 414 |
Prices received for the years ended December 31, 2024 and 2023, respectively, including the impact of derivatives were:
| 2024 | 2023 | Increase / (Decrease) | Increase / (Decrease) | |||||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| Oil Price | $ | 75.80 | $ | 76.33 | $ | (0.53 | ) | (0.69 | )% | |||||||
| Gas Price | $ | 0.43 | $ | 1.93 | $ | (1.50 | ) | (77.72 | )% | |||||||
| NGL Price | $ | 20.25 | $ | 19.64 | $ | 0.61 | 3.11 | % |
Oil and gas production expense increased $15.8 million, or 49.6% to $47.7 million for the year ended December 31, 2024 from $31.9 million for the year ended December 31, 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.
Field service income decreased $4.5 million or 29.5% to $10.9 million for the year ended December 31, 2024 from $15.4 million for the year ended December 31, 2023. Workover rig services, hot oil treatments, saltwater hauling and disposal represent the bulk of our field service operations. These changes reflect decreases in equipment utilization related to the sale of Eastern Oil Well Service Company, effective August 31, 2024.
Field service expense decreased $2.6 million, or 22.4% to $9.1 million for the year ended December 31, 2024 from $11.7 million for the year ended December 31, 2023. Field service expenses primarily consist of wages and vehicle operating expenses. These changes reflect decreases in equipment utilization related to the sale of Eastern Oil Well Service Company, effective August 31, 2024.
Depreciation, depletion, and amortization increased $45.5 million, or 147.0% to $76.5 million for the year ended December 31, 2024 from $31.0 million for the year ended December 31, 2023. These increases reflect the expense related to the new wells placed on production during the twelve months ended December 31, 2024.
General and administrative expense increased $3.2 million, or 21.0% to $18.8 million for the year ended December 31, 2024 from $15.6 million for the year ended December 31, 2023. This increase is primarily due to employee compensation, benefits and other corporate costs.
Gain on sale and exchange of assets of $3.7 million for the year ended December 31, 2024 consists of sales of net mineral and surface acres in various locations in Texas and Oklahoma as well as the sale of our South Texas oilfield service company, Eastern Oil Well Service.
Interest expense increased $1.0 million, or 189.0% to $1.5 million for the year ended December 31, 2024 from $0.5 million for the year ended December 31, 2023. This increase reflects the higher interest and fee rates combined with borrowings throughout the twelve months of 2024 under our revolving credit agreement.
Tax expense of $15.8 million and $6.1 million were recorded for the years ended December 31, 2024 and 2023, respectively. The change in our income tax provision was primarily due to the increase in pre-tax income for the year ended December 31, 2024.