PRIMEENERGY RESOURCES CORPORATION 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 inTexas , andOklahoma . In addition, we own a substantial amount of well servicing equipment. All of our oil and gas properties and interests are located inthe 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. 35
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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 ofHenry 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 improved since the lows of 2020 however we expect prices to remain volatile 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.
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
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
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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.
Net cash provided by operating activities for the year endedDecember 31, 2022 was$33.1 million , compared to$28.6 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 2023, we will continue our focus on preserving financial flexibility and ample liquidity as we manage the risks facing our industry. Our 2023 capital budget is reflective of commodity prices and has been established based on an expectation of available cash flows, with any cash flow deficiencies expected to be funded by borrowings under our revolving credit facility. As we have done historically to preserve or enhance liquidity, we may adjust our capital program throughout the year, divest assets, or enter into strategic joint ventures. The Company maintains a Credit Agreement with a maturity date ofJune 1, 2026 , providing for a credit facility totaling$300 million , with a borrowing base of$60 million . As ofMarch 31, 2023 , the Company has no outstanding borrowings and$60 million in availability under this facility. 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 forMay 2023 . Our oil and gas properties are pledged as collateral for the line of credit and we are subject to certain financial and operational covenants defined in the agreement. We are currently in compliance with these covenants and expect to be in compliance over the next twelve months. If we do not comply with these covenants on a continuing basis, the lenders have the right to refuse to advance additional funds under the facility and/or declare all principal and interest immediately due and payable. Our borrowing base may decrease as a result of lower natural gas or oil prices, operating difficulties, declines in reserves, lending requirements or regulations, the issuance of new indebtedness or for other reasons set forth in our revolving credit agreement. In the event of a decrease in our borrowing base due to declines in commodity prices or otherwise, our ability to borrow under our revolving credit facility may be limited and we could be required to repay any indebtedness in excess of the re-determined borrowing base. 37
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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.
2023 2023
Swap Agreements
Natural Gas (MMBTU) 377,000 $ 3.87
Oil (barrels) 114,200 $ 74.07
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 2022 the Company participated with SEM Operating Company, LLC in four
horizontal wells in Irion County, Texas with 10.3% interest for approximately
$2.35 million and with Ovintiv Mid-Continent, Inc. in four horizontal wells in
Canadian County with an average of 9% interest for $1.77 million . All eight
wells were put into production in August of 2022.
In the fourth quarter of 2022, we began participation in the drilling of 20
horizontal wells located in West Texas operated by three different operators. In
Martin County , we are participating with ConocoPhillips in five 2.5-mile-long
horizontal wells in which the Company has 20.83% interest with a planned capital
expense of $12.1 million . In Reagan County we are participating with Hibernia
Energy III in 10 two-mile horizontals with 25% interest and an expected
investment of $25.6 million . Also in Reagan County , we are participating with
Double Eagle (DE IV) in five two-mile-long horizontals with nearly 50% interest,
carrying an expected net capital outlay of $23.4 million . All twenty of these
West Texas wells are currently drilling or have been completed. All are expected
to be on line in the second quarter of 2023.
In January of 2023, the Company joined Ovintiv USA, Inc. in the spudding of
three 3-mile-long horizontal wells in Canadian County, Oklahoma with 1.96%
interest and an expected investment of $645,000 . Production is expected to begin
in May, 2023. In addition, in March of 2023, Apache Corporation has spud two
3-mile-long horizontals in Upton County, Texas in which the Company has 49.4%
interest with an expected total capital investment of $16,1 million . We
anticipate completion of these two 15,000' long horizontals in Upton County in
May and production to occur in June of 2023.
In total, the Company expects to invest $78 million dollars in these 25
horizontal wells. We prepaid drilling costs of $32 million in December of 2022
and the remaining $46 million estimated drilling and completion expenditures
will occur in 2023. All 25 wells are expected to be completed and on-line in the
second quarter of 2023.
We anticipate that success from the 22 horizontals in West Texas described above
will lead to additional near-term horizontal drilling covering five leasehold
blocks in three counties of West Texas : 29 additional 10,000' long horizontals
in Reagan County with Hibernia, Double Eagle and BTA Oil Producers , ten
additional 12,500' long horizontals in Martin County with ConocoPhillips, and
six additional 15,000' long horizontals in Upton County with Apache. These
anticipated additional 42 drilling proposals will target various proven pay
intervals of the Wolfcamp and Spraberry formations and will require an estimated
$200 million in net capital investment. In addition, we have more than 200
drilling locations that could potentially be developed.
In West Texas the Company maintains an acreage position of 16,940 gross (9,969
net) acres, primarily in Reagan , Upton , Martin , and Midland counties where our
horizontal activity is focused. We believe this acreage
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has significant resource potential in as many as 10 reservoirs, including
benches of the Spraberry,
InOklahoma , the Company's horizontal activity is primarily focused in Canadian,Grady ,Kingfisher ,Garfield ,Major , andGarvin counties where we have approximately 4,113 net leasehold acres in the Scoop/Stack Play. Of this acreage we believe 2,355 net acres holds significant additional resource potential that could support the drilling of as many as 46 new horizontal wells based on an estimate of four wells per multi-section drilling unit, two in the Mississippian and two in theWoodford Shale . In the near term, we anticipate nine new drilling proposals to be received with an estimated net expense of$5.2 million covering 338 net leasehold acres. Proposals may be received on the remaining 2,017 acres, however, rather than participate we may choose to sell the acreage or farm-out receiving cash and retaining an over-riding royalty interest. During 2022, to supplement cash flow and finance our future drilling programs, the Company entered into an agreement with Double Eagle to create a 2,560-acre AMI for the joint development of horizontal wells; as part of this agreement, the Company sold a portion of its interest in this acreage for proceeds of$16.1 million . In addition, in 2022, we sold 240 net acres inReagan County toBTA Oil Producers for proceeds of$1.8 million , and we sold 353 net acres inCanadian County, Oklahoma toPaloma Partners ,IV, Inc. for$1.3 million . Through three other transactions, we divested a minor tract inLea County, NM for a nominal cash consideration and assigned nine wellbores inWest Texas to a third-party operator in exchange for a reduction in our future plugging liability. In this same year, the Company acquired 3.2 net mineral acres inUpton County, Texas for$16,000 . These sales along with our cash flow have allowed the Company to eliminate its bank debt as ofMarch 31, 2023 , with the right to borrow up to$60 million under its current revolving line of credit. 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 2022 and 2021 was$7.4 million and$145 thousand , respectively. The Company expects continued spending under the stock repurchase program in 2023.
Results of Operations:
2022 and 2021 Compared
We reported a net income of$48.7 million for 2022, or$24.91 per share, compared to$2.1 million , or$1.05 per share for 2021. The current year net income reflects production and commodity price increases, partially offset by losses related to derivative instruments. The significant components of income and expense are discussed below. Oil, NGL and gas sales increased$51.1 million , or 69.7% to$124.1 million for the year endedDecember 31, 2022 from$73.1 million for the year endedDecember 31, 2021 . 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 increased an average of$28.31 per barrel, or 41.40% on crude oil, increased an average of$8.73 per barrel, or 32.37% on NGL and increased$2.01 per Mcf, or 57.00% on natural gas during 2022 as compared to 2021. Our crude oil production increased by 201,000 barrels, or 27.24% to 939,000 barrels for the year endedDecember 31, 2022 from 738,000 barrels for the year endedDecember 31, 2021 . Our NGL production increased by 1,000 or 0.24% to 417,000 for the year endedDecember 31, 2022 from 416,000 barrels for the year ended 39
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December 31, 2021 . Our natural gas production increased by 89 MMcf, or 2.75% to 3,325 MMcf for the year endedDecember 31, 2022 from 3,236 MMcf for the year endedDecember 31, 2021 . The changes in crude oil, NGL and natural gas production volumes are a result of new wells placed in production offset by the natural decline of existing properties. The following table summarizes the primary components of production volumes and average sales prices realized for the years endedDecember 31, 2022 and 2021 (excluding realized gains and losses from derivatives). Years ended December 31, Increase / Increase / 2022 2021 (Decrease) (Decrease) Barrels of Oil Produced 939,000 738,000 201,000 27.24 % Average Price Received$ 96.70 $ 68.39 $ 28.31 41.40 % Oil Revenue (In 000's)$ 90,803 $ 50,474 $ 40,329 79.90 % Mcf of Gas Sold 3,325,000 3,236,000 89,000 2.75 % Average Price Received$ 5.54 $ 3.53 $ 2.01 57.00 % Gas Revenue (In 000's)$ 18,428 $ 11,432 $ 6,996 1.20 % Barrels of Natural Gas Liquids Sold 417,000 416,000 1,000 0.24 % Average Price Received$ 35.70 $ 26.97 $ 8.73 32.37 % Natural Gas Liquids Revenue (In 000's)$ 14,887 $ 11,220 $ 3,667 32.68 % Total Oil & Gas Revenue (In 000's)$ 124,118 $ 73,126 $ 50,992 69.73 % 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.
The following table summarizes the results of our derivative instruments for the
years ended
Years ended
December 31,
2022 2021
Oil derivatives - realized gains (losses) $ (12,101 ) $ (3,212 )
Oil derivatives - unrealized (losses) gains 3,713 (4,055 )
Total (losses) gains on oil derivatives$ (8,388 ) $ (7,267 ) Natural gas derivatives - realized (losses) gains (4,543 ) (1,833 ) Natural gas derivatives - unrealized gains (losses) 892 (859 )
Total (losses) gains on natural gas derivatives
Total (losses) gains on oil and natural gas$ (12,039 ) $
(9,959 )
Prices received for the years ended
Increase / Increase /
2022 2021 (Decrease) (Decrease)
Oil Price $ 87.77 $ 64.04 $ 23.73 37.05 %
Gas Price $ 4.44 $ 2.97 $ 1.47 49.64 %
NGL Price $ 35.70 $ 26.97 $ 8.73 32.37 %
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Field service expense increased$1.9 million , or 20.7% to$11.1 million for the year endedDecember 31, 2022 from$9.2 million for the year endedDecember 31, 2021 . Field service expenses primarily consist of wages and vehicle operating expenses which have increased during 2022 related to increased utilization of our equipment services. Depreciation, depletion, amortization and accretion on discounted liabilities increased$1.8 million , or 6.8% to$28.1 million for the year endedDecember 31, 2022 from$26.3 million for the year endedDecember 31, 2021 . The DD&A expense is primarily attributable to our properties inWest Texas andOklahoma , reflecting the addition of new properties offset by the declining cost basis of existing properties.
General and administrative expense increased
Gain on sale and exchange of assets of
Interest expense decreased$1.1 million , or 55.0% to$0.9 million for the year endedDecember 31, 2022 from$2.0 million for the year endedDecember 31, 2021 . This decrease reflects the reduced borrowings under our revolving credit agreement offset by an increase in rates. Tax expense of$10.3 million and$2.5 million were recorded for the years endedDecember 31, 2022 and 2021, respectively. The change in our income tax provision was primarily due to the increase in pre-tax income for the year endedDecember 31, 2022 .
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