PRIMEENERGY RESOURCES CORP 10-Q

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 The Company’s activities include development drilling. Our strategy is to develop the Company’s extensive oil and gas reserves primarily through horizontal drilling. This strategy includes targeting reservoirs with high initial production rates and cash flow as well as targeting reservoirs with lower initial production rates but with higher expected return on investment. We believe that with today’s technology, horizontal development of our reserves provides superior economic results as compared to vertical development, by delivering higher production rates through greater contact and stimulation of a larger volume of reservoir rock while minimizing the surface footprint required to develop those same reserves. Our cash flows depend on many factors, including the price of oil, gas and natural gas liquids (NGL’s), 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 commodity 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. Our financial results depend on many factors, particularly the price of natural gas, crude oil and natural gas liquids and our ability to market our products 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 NGL’s 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 revenue. 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 19,680 gross (12,460 net) acres, 97% of which is located in Reagan, Upton, Martin, and Midland counties of Texas where our current horizontal drilling activity is focused. We believe this acreage has significant resource potential in the Spraberry and Wolfcamp intervals for additional horizontal drilling that could support the drilling of as many as 250 additional horizontal wells. In Oklahoma, we maintain an acreage position of approximately 52,800 gross (10,300 net) acres. Our Oklahoma horizontal development is focused primarily in Canadian, Kingfisher, Grady, and Garvin counties. We believe approximately 3,460 net acres in these counties hold significant additional resource potential that could support the drilling of as many as 49 new horizontal wells based on an estimate of four to ten wells per section, depending on the reservoir target area. Should we choose to participate with a working interest in future development, our share of these future capital expenditures would be approximately $34 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. 14 Table of Contents District Information The following table represents certain reserve and well information as of December 31, 2020. Gulf Coast Mid- Continent West Texas Other Total Proved Reserves as of December 31, 2020 (MBoe) Developed 517 1,575 5,116 6 7,214 Undeveloped — 95 3,126 — 3,221 Total 517 1,670 8,242 6 10,435 Average Daily Production (Boe per day) 297 788 3,178 2 4,265 Gross Productive Wells (Working Interest and ORRI Wells) 239 549 556 170 1,514 Gross Productive Wells (Working Interest Only) 209 485 518 69 1,281 Net Productive Wells (Working Interest Only) 124 217 263 2 606 Gross Operated Productive Wells 158 209 325 — 692 Gross Operated Water Disposal, Injection and Supply wells 9 53 6 — 68 In several of our producing regions, we have field service groups to service our operated wells and locations as well as third-party operators in the area. These services consist of well service support, site preparation, and construction services for drilling and workover operations. Our operations are performed utilizing workover and swab rigs, water transport trucks, hot oil trucks, saltwater disposal facilities, various land excavating equipment, and trucks we own and that are operated by our field employees. Gulf Coast Region Our development, exploitation, exploration, and production activities in the Gulf Coast region are primarily concentrated in southeast Texas. This region is managed from our office in Houston, Texas. Principal producing intervals are in the Wilcox, San Miguel, Olmos, and Yegua formations at depths ranging from 3,000 to 12,500 feet. We had 239 producing wells (124 net) in the Gulf Coast region as of December 31, 2020, of which 158 wells are operated by us. Average net daily production in our Gulf Coast Region in 2020 was 297 Boe. On December 31, 2020, we had 517 MBoe of proved reserves in the Gulf Coast region, which represented 5% of our total proved reserves. We maintain an acreage position of over 11,900 gross (4,300 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, nineteen water transport trucks, two saltwater disposal wells, two hot oilers, 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 operated wells and locations. As of June 30, 2021, 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, 2020, we had 549 wells (217 net) in the Mid-Continent area, of which 209 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 2020 was 788 Boe. On December 31, 2020, we had 1,670 MBoe of proved reserves in the Mid-Continent area, or 16% of our total proved reserves. We maintain an acreage position of approximately 52,800 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 interest in several counties in the Stack and Scoop plays of Oklahoma where drilling is primarily targeting reservoirs of the Mississippian, and Woodford formations. As of June 30, 2021, in the Mid-Continent region, the Company was participating in the completion of four wells included as Proved Undeveloped in the 2020 year-end reserve report: one for 9.9% interest and three for less than one percent interest. In addition, the Company has committed to participate for 11.25% working interest in the drilling and completion of four wells in Canadian County, Oklahoma. Our share of these wells will be approximately $1.98 million. As of August 16, 2021, these four wells have been drilled and are currently awaiting completion. West Texas Region Our West Texas activities are concentrated in the Permian Basin of West Texas and New Mexico. The basin covers more than 75,000 square miles and extends across 52 Counties. The Wolfcamp and Spraberry reservoirs of this basin are among the largest contiguous accumulations of oil and gas in the United States. Production from these reservoirs is West Texas Intermediate Sweet Crude oil and high quality casing-head gas. This region is managed from our office in Midland, Texas. As of December 31, 2020, we 15 Table of Contents had 556 wells (263 net) in the West Texas area, of which 325 wells are operated by us. Principal producing intervals are in the Wolfcamp and Spraberry formations at depths ranging from 5,500 to 12,500 feet. The average net daily production in Our West Texas Region in 2020 was 3,178 Boe. On December 31, 2020, we had 8,242 MBoe of proved reserves in the West Texas area, or 79% of our total proved reserves. We maintain an acreage position of approximately 19,679 gross (12,461 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 in our operated wells and locations. In the spring of 2020, the Company participated with Apache Corporation in the drilling of six horizontal wells on our Kashmir acreage in Upton County, Texas. In March of 2021, we drilled an additional three wells on the same acreage block. As of June 30, 2021, the Company was participating in the completion of these nine horizontal wells for an average of 47.5% interest with an estimated total investment of approximately $27.8 million. As of August 23, 2021, all nine wells have been completed and are in the process of being placed on production. 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, 2020. The professional qualifications of the technical persons primarily responsible for overseeing the preparation of the reserve estimates can be found in the Company’s 2020 Form 10K Exhibit 99.1, the Ryder Scott Company, L.P. Report on Registrant’s Reserves Estimates. In matters related to the preparation of our reserve estimates, our district managers report to the Engineering Data manager, who maintains oversight and compliance responsibility for the internal reserve estimate process and provides oversight for the annual preparation of reserve estimates of 100% of our year-end reserves by our independent third-party engineers, Ryder Scott Company, L.P. The members of our district and central groups consist of degreed engineers and geologists with between approximately twenty and thirty-five years of industry experience, and between eight and twenty-five years of experience managing our reserves. Our Engineering Data manager, the technical person primarily responsible for overseeing the preparation of reserves estimates, has over thirty years of experience, holds a Bachelor’s degree in Geology and an MBA in finance, and is a member of the Society of Petroleum Engineers and American Association of Petroleum Geologist. All of our reserves are located within the continental United States. The following table summarizes our oil and gas reserves at each of the respective dates: 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) 2018 6,404 2,707 21,065 12,622 10 12 124 43 6,414 2,719 21,189 12,665 2019 4,381 2,914 19,995 10,268 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 (a) In computing total reserves on a barrel 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. On December 31, 2020, the Company had 3,221 Mboe of proved undeveloped (PUD) reserves attributable to 13 wells operated by others, three of which are new wells spud in 2020 but not drilled until the first quarter of 2021, and 10 of which that were drilled as of year-end but not yet completed. The three new horizontal wells along with six uncompleted wells are located on our Kashmir tract in Upton County, Texas. They are operated by Apache Corporation and in the process of being completed and will be on production in the third quarter of 2021. These nine wells account for 3,127 Mboe of the total undeveloped reserves at year-end. Our average 47.5% share of the total cost of these nine horizontal wells will be approximately $27.8 million. The four remaining PUD wells, drilled but not completed at year-end, are located in Grady County, Oklahoma and account for 95 Mboe of the total undeveloped reserves. 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. 16 Table of Contents We employ technologies to establish proven reserves that have demonstrated consistent results capable of repetition. The technologies being used in the estimation of our proved reserves include, but are not limited to, decline curve and volumetric analysis, analogy, geologic mapping, as well as evaluation of reservoir properties, production, 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, 2020, 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 2018 $ 239,337 $ 161,376 $ 767 $ 525 $ 240,104 $ 161,901 $ 23,992 $ 137,909 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 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 before 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. Natural gas prices, based on the twelve-month average of the first of the month Henry Hub index price, were $1.985 per MMBtu in 2020 as compared to $2.58 per MMBtu in 2019, and $3.10 per MMBtu in 2018. Oil prices, based on the NYMEX first of the month average price, were $39.57 per barrel in 2020 as compared to $55.69 per barrel in 2019, and $65.56 per barrel in 2018. RECENT ACTIVITIES Maintaining a strong balance sheet and ample liquidity are key components of our business strategy. For 2021, we will continue our focus on preserving financial flexibility and ample liquidity as we manage the risks facing our industry. Our 2021 capital budget 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. 17 Table of Contents In Upton County, West Texas, we are actively developing a contiguous 3,260 acre Area of Mutual Interest (AMI) with our joint venture partner, Apache Corporation. In this acreage block, the Company has leasehold acres with interest between 14% and 56% depending on the particular lease and depth being developed. Development to date has been from the Wolfcamp “B” reservoir where we have 34 horizontals currently producing. Planning now is for the development of the shallower Upper Wolfcamp, Jo Mill, and Lower Spraberry reservoirs that have been proven economical by near-offset completions. We have 36 horizontals slated for the development of these three reservoirs, with 18 of these planned as 3-mile laterals. In addition, there is a Middle Spraberry target reservoir that will likely be developed with 12 horizontals. In total, we anticipate 48 horizontal wells will develop these four reservoirs with a cost estimate of $146 million net to the Company. 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. Two miles east of the AMI acreage described above, the Company is also developing a 1,280-acre block with Apache Corporation. Initially, six horizontal wells developed the Middle Wolfcamp reservoir. In 2019, three horizontals proved the viability of production from the Wolfcamp “A”, Jo Mill, and Lower Spraberry. Since early 2020, the Company and Apache drilled nine more laterals targeting these three reservoirs, three of which were drilled in the first quarter of 2021. As of August 23, 2021, all nine wells have been completed and are in the process of being placed on production. Prime holds an average 47.5% working interest in these wells. Our share of the cost of these nine horizontal wells will be approximately $27.8 million in total. In addition to these shallow reservoirs, the Middle Spraberry is also being considered as a target. Future development of the Middle Spraberry is likely to occur using four horizontals. The approximate completed cost of these four wells is $30.2 million, with the Company’s share being $14.2 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 and have been producing from the Wolfcamp. The Company owns between 35% and 38% interest in various leases of this joint venture acreage where ConocoPhillips is the operator. No near-term additional drilling plans have been received, however, development of offset acreage by other operators has demonstrated the potential for good economic production from multiple landing zones on our acreage block. In Reagan County, Texas, the Company and Pioneer Natural Resources have agreed to jointly develop approximately 3,680 gross acres. This agreement facilitates the drilling of as many as 108 horizontal laterals where the company would have an average of 34.5% working interest and invest approximately $236 million. We believe this agreement represents significant future value for PrimeEnergy. Also in Reagan County, Texas, the Company has separate joint development projects with BTA Producers, Inc. and Hibernia Energy III, LLC. These two development blocks can accommodate the drilling of 144 horizontal wells to produce from five prospective reservoirs, four of which are proven. The Company’s share is expected to be 50% and the potential investment net to the Company would be approximately $442 million. The actual number of wells eventually drilled, and the cost and the timing of such wells are dependent upon many factors including commodity market conditions. In Canadian County, Oklahoma, the Company is participating in the drilling of four 2-mile long horizontal laterals operated by Ovintiv Mid-Continent Inc. These wells have spud and will target reservoirs of the Mississippian and Woodford formations at roughly 8,900’. As of August 16, 2021, the wells have been drilled and are awaiting completion. The Company has an 11.25% interest and will invest approximately $1.98 million in the drilling and completion of these wells. 18 Table of Contents 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 six months ended June 30, 2021 was $11.4 million compared to $8.8 million for the same period of 2020. 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 2021, we will continue our focus on preserving financial flexibility and ample liquidity as we manage the risks facing our industry. Our 2021 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. We are actively in discussions with financial partners for funding to develop our asset base and, if required, pay down our revolving credit facility should our borrowing base become limited due to the deterioration of commodity prices. The Company maintains a Credit Agreement with a maturity date of February 15, 2023, providing for a credit facility totaling $300 million, with a borrowing base of $40 million. As of August 23, 2021, the Company has $32 million in outstanding borrowings and $8 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 for October 2021. 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. Accordingly, as of June 30, 2021, the Company has in place the following swap and put agreements for oil and natural gas. 2021 2022 2023 2021 2022 2023 Swap Agreements Natural Gas (MMBTU) 734,000 928,000 131,000 $ 2.55 $ 2.67 $ 2.81 Oil (barrels) 157,500 196,200 27,200 $ 53.57 $ 51.99 $ 50.31 The Company’s activities include development 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. In 2016, based upon the results of horizontal wells and historical vertical well performance, we decided to reduce the number of vertical wells in our drilling program and focus primarily on horizontal well drilling. We believe horizontal development of our resource base provides superior returns relative to vertical development, due to the ability of horizontals to come in contact with and drain from a greater volume of reservoir rock over more acreage, with less infrastructure, and thus at a lower cost of development per acre. Our primary focus is the development of our leasehold acreage in the Permian Basin of West Texas where the Company currently holds an acreage position of 19,680 gross (12,460 net) acres, the majority of which is in Reagan, Upton, Martin and Midland counties. We believe this acreage has significant resource potential in as many as 10 reservoirs, including benches of the Spraberry, Jo Mill, and Wolfcamp, and can support the potential drilling of as many as 250 additional horizontal wells. 19 Table of Contents The Middle Wolfcamp has been the primary target for production in the area until, however, in 2019, in Upton County, the Company drilled three horizontal wells with Apache Corporation targeting shallower reservoirs in the Wolfcamp “A”, the Jo Mill, and the Lower Spraberry. These three test wells proved the productive capability of these reservoirs for the 1,280 acre block in which they were drilled and led to the drilling of nine additional wells in early 2020 and the first quarter of 2021. As of August 23, 2021, all nine wells have been completed and are in the process of being placed on production. We have an average 47.5% interest in these wells and anticipated a total investment net to the Company of approximately $27.8 million. The successful development of these reservoirs has proven the productive potential of these reservoirs on our nearby 3,260-acre AMI block with Apache Corporation in Upton County, Texas. Here the Company holds between 14% and 56% interest and anticipates the future development of as many as 48 additional horizontal wells targeting four reservoirs from the Wolfcamp “A” through the Middle Spraberry. The cost of such development will be approximately $370 million with the Company’s share being approximately $146 million. The actual number of wells that will be drilled, the cost, and the timing of drilling will vary based upon many factors, including commodity market conditions. In Reagan County, Texas, the Company holds 12,700 Gross (8.870 net) acres with exceptional potential. Offset operators have proven the productive capability of four reservoirs from the Middle Wolfcamp to the Lower Spraberry. Here the Company could participate in as many as 352 horizontals with a net cost of approximately $890 million. Near-term development plans being discussed include the drilling of three 12,500’ laterals on one acreage block, and six horizontal laterals on a second acreage block with laterals from 7,500’ to 10,000’ in length. The Company’s share of these wells would average about 37.5% and cost approximately $35.2 million net. 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. In Oklahoma, the Company’s horizontal activity is primarily focused in Canadian, Grady, Kingfisher, Garfield, Major, and Garvin counties where we have approximately 3,460 net leasehold acres with exceptional development potential. We believe this acreage could support the drilling of as many as 49 new horizontal wells based on an estimate of six wells per section: three in the Mississippian and three in the Woodford Shale. Should we choose to participate in future development, our share of the capital expenditures would be approximately $34 million at an average 10% ownership; otherwise the Company will sell its rights for cash, or cash plus a royalty or working interest. 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 in place both a stock repurchase program and a limited partnership interest repurchase program. Spending under these programs in 2020 was $1.45 million. The Company expects continued spending under these programs in 2021. RESULTS OF OPERATIONS 2021 and 2020 Compared We reported net losses of $3.9 million, or $1.93 per share and $2.4 million, or $1.20 per share for the six and three months ended June 30, 2021, respectively, as compared to net losses of $6.4 million, or $3.23 per share and $6.3 million, or $3.14 per share for the six and three months ended June 30, 2020, respectively. Current year net income reflects decreases in production offset by commodity price increases over the three and six months ended June 30, 2021, 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 $10.7 million, or 230.3% from $4.7 million for the three months ended June 30, 2020 to $15.4 million for the three months ended June 30, 2021 and $10.6 million, or 60.6% from $17.5 million for the six months ended June 30, 2020 to $28.0 million for the six months ended June 30, 2021. 20 Table of Contents The following tables summarizes the primary components of production volumes and average sales prices realized for the three and six months ended June 30, 2021 and 2020 (excluding realized gains and losses from derivatives). Six months ended June 30, 2021 2020 Increase / (Decrease) Increase / (Decrease) Barrels of Oil Produced 328,000 378,000 (50,000 ) (13.2 )% Average Price Received $ 60.77 $ 37.89 $ 22.88 60.4 % Oil Revenue (In 000’s) $ 19,934 $ 14,324 $ 5,610 39.2 % Mcf of Gas Sold 1,445,000 1,812,000 (367,000 ) (20.36 )% Average Price Received $ 2.73 $ 0.77 $ 1.96 254.5 % Gas Revenue (In 000’s) $ 3,950 $ 1,389 $ 2,561 184.4 % Barrels of Natural Gas Liquids Sold 195,000 213,000 (18,000 ) (8.5 )% Average Price Received $ 21.28 $ 8.16 $ 13.12 160.7 % Natural Gas Liquids Revenue (In 000’s) $ 4,149 $ 1,738 $ 2,411 138.7 % Total Oil & Gas Revenue (In 000’s) $ 28,033 $ 17,451 $ 10,582 60.6 % 21 Table of Contents Three months ended June 30, 2021 2020 Increase / (Decrease) Increase / (Decrease) Barrels of Oil Produced 165,000 144,000 21,000 14.6 % Average Price Received $ 64.63 $ 25.09 $ 39.54 157.6 % Oil Revenue (In 000’s) $ 10,664 $ 3,613 $ 7,051 195.2 % Mcf of Gas Sold 780,000 874,000 (94,000 ) (10.8 )% Average Price Received $ 2.94 $ 0.62 $ 2.32 373.9 % Gas Revenue (In 000’s) $ 2,292 $ 543 $ 1,749 322.1 % Barrels of Natural Gas Liquids Sold 109,000 56,000 53,000 94.6 % Average Price Received $ 22.06 $ 5.76 $ 16.30 282.9 % Natural Gas Liquids Revenue (In 000’s) $ 2,404 $ 495 $ 1,909 385.7 % Total Oil & Gas Revenue (In 000’s) $ 15,360 $ 4,651 $ 10,709 230.3 % 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 three and six months ended June 2021 and 2020: Three Months Ended June 30, Six Months Ended June 30, 2021 2020 2021 2020 ($ in thousand) Oil derivatives – realized gains (losses) $ (484 ) $ 4,539 $ (636 ) $ 5,545 Oil derivatives – unrealized gains (losses) (3,987 ) (5,397 ) (4,883 ) 854 Total gains (losses) on oil derivatives $ (4,471 ) $ (858 ) $ (5,519 ) $ 6,399 Natural gas derivatives – realized gains (losses) $ (217 ) $ 218 $ (277 ) $ 409 Natural gas derivatives – unrealized gains (losses) (1,070 ) (218 ) (1,085 ) 87 Total gains (losses) on natural gas derivatives $ (1,287 ) $ — $ (1,362 ) $ 496 Total gains (losses) on oil and natural gas derivatives $ (5,758 ) $ (858 ) $ (6,881 ) $ 6,895 Prices received for the six months ended June 30, 2021 and 2020, respectively, including the impact of derivatives were: 2021 2020 Oil Price $ 58.84 $ 52.56 Gas Price $ 2.54 $ 0.99 NGLS Price $ 21.28 $ 8.16 Field service income increased $0.5 million or 21.8% from $2.4 million for the second quarter 2020 to $2.9 million for the second quarter 2021 however decreased $1.5 million, or 22.7% from $6.7 million for the six months ended June 30, 2020 to $5.2 million for the six months ended June 30, 2021. These changes reflect the variation in utilization and rates resulting from the oil and gas price volatility during these periods. Workover rig services, hot oil treatments, saltwater hauling and disposal represent the bulk of our field service operations. Lease operating expense decreased $0.9 million or 15.1% from $6.2 million for the second quarter 2020 to $5.3 million for the second quarter 2021 and decreased $2.0 million or 15.9% from $12.6 million for the six months ended June 30, 2020 to $10.6 million for the six months ended June 30, 2021. This decrease is primarily due to the sale or shut-in of high lifting cost properties during 2020 offset by higher production taxes related to higher commodity prices. Field service expense increased $0.5 million or 23.5% from $1.9 million for the second quarter 2020 to $2.4 million for the second quarter 2021 and decreased $1.1 million, or 20.9% from $5.4 million for the six months ended June 30, 2020 to $4.3 million for the six months ended June 30, 2021. Field service expenses primarily consist of wages and vehicle operating expenses which have fluctuated during the three and six months ended June 30, 2021 compared with the same periods of 2020. These changes reflect the variation in utilization and rates resulting from the oil and gas price volatility during these periods. 22 Table of Contents Depreciation, depletion, amortization and accretion on discounted liabilities decreased $0.3 million, or 4.2% from $6.9 million for the second quarter 2020 to $6.6 million for the second quarter 2021 and $2.0 million, or 13.2% from $15.1 million for the six months ended June 30, 2020 to $13.1 million for the six months ended June 30, 2021. These declines reflect the decrease in the property basis combined with production increases in 2021. General and administrative expense decreased $5.2 million, or 50.4% from $10.3 million for the six months ended June 30, 2020 to $5.1 million for the six months ended June 30, 2021, and decreased $0.1 million, or 3.8% from $2.6 million for the three months ended June 30, 2020 to $2.5 million for the three months ended June 30, 2021. These changes reflect staff reductions and decreases in compensation and benefits implemented in during the past year. Interest expense decreased from $500 thousand for the second quarter 2020 to $484 thousand for the second quarter 2021 and from $1.2 million for the six months ended June 30, 2020 to $1.0 million for the six months ended June 30, 2021. This decrease reflects the increase in rates and lower current borrowings under our revolving credit agreement. Income tax benefit for the June 30, 2021 and 2020 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.