PRIMEENERGY RESOURCES CORPORATION 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 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. OnJanuary 30, 2020 , theWorld Health Organization ("WHO") announced a global health emergency due to the COVID-19 outbreak, which originated inWuhan, China , and the risks to the international community as the virus spreads globally beyond its point of origin. InMarch 2020 , theWHO classified the COVID-19 outbreak as a pandemic, based on the rapid increase in exposure globally. In addition, inMarch 2020 , members ofOPEC failed to agree on production levels which has caused an increased supply and has led to a substantial decrease in oil prices and an increasingly volatile market. The oil price war ended with a deal to cut global petroleum output but did not go far enough to offset the impact of COVID-19 on demand. There has been an increase in supply which has pushed prices down further since March. If the depressed pricing continues for an extended period it will lead to i) further reductions in the borrowing base under our credit facility which would require us to make additional borrowing base deficiency payments, ii) reductions in reserves, and iii) additional impairment of proved and unproved oil and gas properties. We also expect disclosures of supplemental oil and gas information to be impacted by price declines. In response to recent commodity prices our efforts to reduce costs include reducing operating costs and electing to shut-in marginal wells. The Company will continue to review field operations to minimize costs and identify wells for short term shut-ins through May and June. The Company has also implemented a reduction in workforce to further reduce general and administrative costs. The full impact of the COVID-19outbreak and the decline in oil prices continues to evolve as of the date of this report. As such, it is uncertain as to the full magnitude that these events will have on the Company's financial condition, liquidity, and future results of operations. 14
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Management is actively monitoring the global situation on its financial condition, liquidity, operations, suppliers, industry, and workforce. Given the daily evolution of the COVID-19 outbreak and the global responses to curb its spread, the Company is not able to estimate the effects of the COVID-19 outbreak on its results of operations, financial condition, or liquidity for fiscal year 2020. These matters may have a continued material adverse impact on economic and market conditions and trigger a period of global economic slowdown, which may impair the Company's asset values, including reserve estimates. Further, consumer demand has decreased since the spread of the outbreak and new travel restrictions placed by governments in an effort to curtail the spread of the coronavirus. Although the Company cannot estimate the length or gravity of the impacts of these events at this time, if the pandemic and/or decreased oil prices continue, they may have a material adverse effect on the Company's results of future operations, financial position, and liquidity in fiscal year 2020. 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. The price of oil and natural gas has fallen significantly since the beginning of 2020, due in part to failedOrganization of Petroleum Exporting Countries ("OPEC") negotiations as well as concerns about the COVID-19 pandemic and its impact on the worldwide economy and global demand for oil and gas. The resulting precipitous decline in oil and gas pricing experienced duringMarch 2020 , through the date of this report, if prolonged. or a further deterioration of the market price for oil and natural gas, will negatively impact our cash flows. We are the operator of the majority of our developed and undeveloped acreage which is nearly all held by production. In thePermian Basin ofWest Texas and easternNew Mexico the Company maintains an acreage position of approximately 20,400 gross (12,700 net) acres, 97% of which is located inReagan ,Upton ,Martin , andMidland counties ofTexas 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. InOklahoma we maintain an acreage position of approximately 81,800 gross (10,900 net) acres. OurOklahoma horizontal development is focused primarily in Canadian,Kingfisher ,Grady , andGarvin 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 52 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$40 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 reserve and well information as ofDecember 31, 2019 . Gulf Mid- West Appalachian Coast Continent Texas Other Total Proved Reserves as of December 31, 2019 (MBoe) Developed 296 726 2,013 7,582 11 10,628 Undeveloped - - 81 3,526 - 3,607 Total 296 726 2,094 11,108 11 14,235 Average Daily Production (Boe per day) 240 348 840 3703 4 5,133 Gross Productive Wells (Working Interest and ORRI Wells) 528 263 567 561 105 2,024 Gross Productive Wells (Working Interest Only) 481 233 418 522 45 1,699 Net Productive Wells (Working Interest Only) 451 143 216 257 4 1,071 Gross Operated Productive Wells 438 125 144 298 - 1,005 Gross Operated Water Disposal, Injection and Supply wells 1 7 44 7 - 59 15
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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 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.
Our Appalachian activities are concentrated primarily inWest Virginia . This region is managed from our office inCharleston, West Virginia . Our assets in this region include a large acreage position and a high concentration of wells. AtDecember 31, 2019 , we had interest in 481 wells (451 net), of which 438 wells are operated. Multiple producing intervals here include the Big Lime, Injun, Blue Monday, Weir,Berea ,Gordon andDevonian Shale formations at depths primarily ranging from 1,600 to 5,600 feet. Average net daily production in 2019 was 240 Boe. While natural gas production volumes from Appalachian reservoirs are relatively low on a per-well basis compared to other areas ofthe United States , the productive life of Appalachian reserves is relatively long. AtDecember 31, 2019 , we had 296 MBoe of proved developed reserves (substantially all natural gas) in the Appalachian region, constituting 2.1% of our total proved reserves. We maintain an acreage position of approximately 35,790 gross (35,350 net) acres in this region, primarily inCalhoun ,Clay , andRoane counties. We operate a small field service group in this region utilizing one swab rig, one paraffin truck, one saltwater hauling truck and limited excavating equipment to primarily service our own operated wells and locations. As ofMarch 31, 2020 , the Appalachian region has no wells in the process of being drilled, no waterfloods in the process of being installed and no other related activities of material importance.
Our development, exploitation, exploration and production activities in theGulf Coast region are primarily concentrated in southeastTexas . This region is managed from our office inHouston, 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 233 producing wells (143 net) in theGulf Coast region as ofDecember 31, 2019 , of which 125 wells are operated by us. Average net daily production in 2019 was 348 Boe. AtDecember 31, 2019 , we had 726 MBoe of proved reserves in theGulf Coast region, which represented 5.1% of our total proved reserves. We maintain an acreage position of over 12,700 gross (5,120 net) acres in this region, primarily inDimmit andPolk counties. We operate a field service group in this region from a field office inCarrizo Springs, Texas utilizing four workover rigs, nineteen 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. As ofMarch 31, 2020 , theGulf 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 centralOklahoma . This region is managed from our office inOklahoma City, Oklahoma . As ofDecember 31, 2019 , we had 418 wells (216 net) in the Mid-Continent area, of which 144 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 2019 was 840 Boe. AtDecember 31, 2019 , we had 2,094 MBoe of proved reserves in the Mid-Continent area, or 14.7% of our total proved reserves. We maintain an acreage position of approximately 55,880 gross (10,690 net) acres in this region, primarily in Canadian,Kingfisher ,Grant ,Major , andGarvin counties. We operate a field service group in this region from a field office inElmore City , utilizing one workover rig and one saltwater hauling truck. Our Mid-Continentregion 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 ofOklahoma where drilling is primarily targeting reservoirs of the Mississippian, andWoodford formations. As ofMarch 31, 2020 , in the Mid-Continent region, the Company was is participating in the drilling and/or completion of four wells, with overriding royalty only in eight additional wells, all included as Proved Undeveloped in the 2019 year-end reserve report.
OurWest Texas activities are concentrated in thePermian Basin inTexas andNew Mexico . The Spraberry field was discovered in 1949, encompasses eight counties inWest Texas and the Company believes it is the largest oil field inthe United States . The field is approximately 150 miles long and 75 miles wide at its widest point. The oil produced is West Texas Intermediate Sweet, and the gas produced is casing-head gas with an average energy content of 1,400 Btu. The oil and gas are produced primarily from five intervals; the Upper andLower Spraberry , the Wolfcamp, theStrawn , and theAtoka , at depths ranging from 6,700 feet to 11,300 feet. This region is managed from our office inMidland, Texas . As ofDecember 31, 2019 , we had 522 wells (257 net) in theWest Texas area, of which 298 wells are operated by us. Principal producing intervals are in the Spraberry, Wolfcamp, and San Andres formations at depths ranging from 4,200 to 12,500 feet. Average net daily production in 2019 was 3,703 Boe. AtDecember 31, 2019 , we had 11,108 MBoe of proved reserves in theWest Texas area, or 78% of our total proved reserves. We maintain an acreage position of approximately 19,910 gross (12,560 net) acres in thePermian Basin inWest Texas , primarily inReagan ,Upton ,Martin andMidland 16
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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 own operated wells and locations. AtDecember 31, 2019 , the Company had committed to participate in the drilling of ten Proved Undeveloped horizontal drilling locations. Seven of the nine wells were drilled byApril 15, 2020 , but are not expected to be completed and producing until the fourth quarter of 2020.
Reserve Information:
Our interests in proved developed and undeveloped oil and gas properties, including the interests held by the Partnerships, have been evaluated byRyder Scott Company, L.P. for each of the three years endedDecember 31, 2019 . The professional qualifications of the technical persons primarily responsible for overseeing the preparation of the reserve estimates can be found in Exhibit 99.1, theRyder 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 twenty-five years of experience, holds a Bachelor degree in Geology and an MBA in finance and is a member of the Society ofPetroleum 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. 17
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All of our reserves are located within the continentalUnited States . The following table summarizes our oil and gas reserves at each of the respective dates: Reserve Category Proved Developed Proved Undeveloped Total Oil NGLs Gas Total Oil NGLs Gas Total Oil NGLs Gas Total As of December 31, (MBbls) (MBbls) (MMcf) (MBoe) (MBbls) (MBbls) (MMcf) (MBoe) (MBbls) (MBbls) (MMcf) (MBoe) 2017 5,333 1,703 17,143 9,893 505 156 710 779 5,838 1,859 17,853 10,672 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
(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.
AtDecember 31, 2017 our reserve report included 779 MBoe of proved undeveloped reserves attributable to 22 horizontal wells that were all completed in 2018, therefore, 100% of these reserves were converted to proved developed in the 2018 year-end reserves report. In 2018, the Company drilled and completed seventeen horizontal wells inWest Texas and eleven horizontal wells inOklahoma . In addition, the Company added reserves through overriding royalty interest in 16 wells, primarily inOklahoma andTexas . At year-end 2018, thirteen of the seventeen wells completed in 2018 were designated as Shut-In: eight in ourWest Texas horizontal development program, which were brought on production in February, 2019, and five in our Oklahoma Scoop-Stack development program, which were brought on production in March, 2019. AtDecember 31, 2018 , our reserve report included 43 MBoe of proved undeveloped reserves attributable to eight horizontal wells that had been drilled but had not yet been completed: three of these were completed in 2019, converting 24 Mboe of undeveloped reserves to proved developed, and five remained uncompleted as ofDecember 31, 2019 , which account for 18 Mboe of the 43 Mboe. The Company has 9% ownership in one of these five wells and less than 1% in four wells. In 2019, inWest Texas , in addition to the eight wells classified as Shut-in at year-end 2018 that were brought on production in February, we participated in the drilling and completion of three wells on ourKashmir tract: two wells with an average 49% interest, and a third well for 5.3% interest. One of each of these wells was completed in the Wolfcamp "A",Jo Mill , andLower Spraberry . All three wells were brought on production in May of 2019. In ourOklahoma , 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 Slash, Osborn, and Leon tracts, with an average 1.34% interest. In addition, three wells drilled inOklahoma in 2018, designated as proved undeveloped at year-end 2018, were completed in 2019 converting 24 Mboe of reserves to proved developed. Also inOklahoma , six wells designated as Shut-in onDecember 31, 2018 , were brought into production in 2019: five located on our Ruthie tract, and one on our Braum tract. In theGulf Coast region, we added production through the recompletion of three vertical wells inPolk 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. AtDecember 31, 2019 , the Company had 3,607 Mboe of undeveloped reserves attributable to 22 wells operated by others that are anticipated to be drilled and completed primarily in 2020: ten of these are located in ourWest Texas horizontal development program and account for 3,526 Mboe of the total, and 12 wells are located in our Oklahoma Scoop-Stack horizontal program and account for 81 Mboe of the total. Nine of the ten wells inWest Texas are located on our 1,300 acreKashmir tract inUpton County , operated by Apache Corporation and, as ofApril 15, 2020 , six of these have been drilled and are awaiting completion, which is expected to occur in the fourth quarter of 2020. Our average 47.76% share of the cost of these six horizontal wells will be approximately$19.4 million . Drilling of the remaining three wells will likely occur in 2021. In the first quarter of 2020, we have participated with 7.7% interest in the drilling of a well inUpton County, Texas by Pioneer Natural Resources that is expected to be completed in the second quarter of 2020. The Company's net cost in this horizontal well will be approximately$580,400 . Additional drilling and future development plans will be established based on an expectation of available cash flows from operations and availability of funds under our revolving credit facility. We employ technologies to establish proved reserves that have been demonstrated to provide consistent results capable of repetition. The technologies and economic data being used in the estimation of our proved reserves include, but are not limited to, electrical logs, radioactivity logs, geologic maps, production data, and well test data. The estimated reserves of wells with sufficient production history are estimated using appropriate decline curves. Estimated reserves of producing wells with limited production history and for undeveloped locations are estimated using performance data from analogous wells in the area. These wells are considered analogous based on production performance from the same formation and with similar completion techniques. 18
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The estimated future net revenue (using current prices and costs as of those dates) and the present value of future net revenue (at a 10% discount for estimated timing of cash flow) for our proved developed and proved undeveloped oil and gas reserves at the end of each of the three years endedDecember 31, 2019 , are summarized as follows (in thousands of dollars): Proved Developed Proved Undeveloped Total Present Present Present Present Value 10 Value 10 Value 10 Value 10 Standardized Of Future Of Future Of Future Of Future Measure of Future Net Net Future Net Net Future Net Net Income Discounted As of December 31, Revenue Revenue Revenue Revenue Revenue Revenue Taxes Cash flow 2017$ 160,737 $ 111,614 $ 13,564 $ 6,100 $ 174,301 $ 117,714 $ 10,800 $ 106,914 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 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 withU.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 withU.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 withSEC specifications andU.S. generally accepted accounting principles, changes in market prices subsequent toDecember 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 theSEC , omitted from consideration in making this evaluation for theSEC case. Actual volumes produced, prices received and costs incurred may vary significantly from theSEC case. RECENT ACTIVITIES The Company's activities include development and exploratory drilling. Our strategy is to develop the Company's extensive oil and gas reserves primarily through horizontal drilling. This strategy includes targeting reservoirs with high initial production rates and cash flow as well as other reservoirs with lower initial production rates but that are sustained longer and that are expected to deliver a 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. Maintaining a strong balance sheet and ample liquidity are key components of our business strategy. For 2020, we will continue our focus on preserving financial flexibility and ample liquidity as we manage the risks facing our industry. Our 2020 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. 19
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UnderSEC rules governing the scheduling of development of proved undeveloped (PUD) reserves, our year-end reserve report includes only those 12 PUD locations that at year-end had been drilled but not yet completed, along with ten new locations originally slated to be drilled in 2020. Of these ten, the Company is participating for an average 42% in seven wells that have been drilled as ofApril 15, 2020 , and are awaiting completion. Of the 12 locations drilled but not completed at year-end 2019, the Company has 10% interest in one well and less than one percent interest in each of three wells, and over-riding royalty interest only in eight wells. Since the start of ourWest Texas horizontal drilling program in 2015 and through the fourth quarter of 2019 the Company has participated in 67 horizontal wells in thePermian Basin , 11 of which were brought into production in 2019. As of year-end, the Company has invested approximately$104 MM. Of the total 67 horizontal wells in this program, the Company has an average of 28.19% interest in 52 wells, and less than one percent interest in 15 wells. Of the 11 wells brought on production in 2019, the Company has 49% interest in eight wells on our CC-33 tract that are one-mile in length, as well as an average 49% interest in two wells, and 5.3% interest in one well that are each two-miles in length, located on ourKashmir tract. Our investment in these 11 new horizontal wells was approximately$31.5 million , including production facilities. InUpton County ,West 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, in this block, eight wells drilled horizontally in the Wolfcamp "B", were participated in for 49% interest and brought on production in February, 2019. This is believed to be full development of the Wolfcamp "B" reservoir for this lease block. Apache will likely now set its sights on development of the Upper Wolfcamp,Jo Mill , andLower Spraberry reservoirs for this block, following the recent successful testing in 2019 of these reservoirs on our offset 1,300 acre lease block. Given the favorable results achieved by the initial three wells on this block, it is expected that as many as 54 additional horizontals will be slated for development on this 3,260 acre block in the near future. The cost of such development would be approximately$370.6 million with the Company's share being approximately$170.8 million . In addition to the 54 wells likely to be drilled for these three reservoirs, there is a fourth target reservoir, the Middle Spraberry, that is also prospective for future development. The potential of the Middle Spraberry on the 3,280 acre block is for 18 horizontal wells to be drilled and completed at a gross cost of approximately$126.3 million with the Company's share being approximately$61.8 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 is also developing an offsetting 1,300-acre block inUpton 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 theJo Mill , and one in the Lower Spraberry, confirming the economic viability of these reservoirs on our acreage. Prime holds between 5% and 48% working interest in various depths of this acreage, and of the$26.7 million development cost for these three wells, our share was approximately$9.2 million . As a result of the success of these initial three wells, nine new horizontals have been spud in the first quarter of 2020 and six of these were finished being drilled in April. These six are expected to be on production in the fourth quarter of 2020. Our average 47.76% share of the cost of these six horizontal wells will be approximately$21 million . Drilling of the remaining three wells is expected to be delayed until 2021. In addition to the nine new development locations in the Wolfcamp "A",Jo Mill andLower Sprayberry of our 1,300-acre block with Apache Corporation, there are four locations in the Middle Spraberry that are likely to be considered for future development at an estimated gross cost of approximately$30.2 million , with the Company's share being approximately$14.2 million . Along with the six horizontal wells drilled in early 2020 inUpton County , the Company participated for 7.7% interest in the horizontal drilling of a well operated by Pioneer Natural Resources that is expected to be completed in the fourth quarter of 2020. Our total net expenditure for this well is estimated to be$580,400 . Also in thePermian Basin ofWest Texas , we are developing a 965-acre block with Concho Resources inMartin County, Texas . In 2016 and 2017, four horizontal wells were drilled and completed and put on production. The Company owns 35% to 38% interest in this joint venture acreage where Concho Resources is the operator. No near-term additional drilling plans have been received from Concho Resources, however, offset operators have been actively drilling and their results are encouraging for the future development of multiple landing zones within this acreage block. Since the start of our Oklahoma Scoop-Stack horizontal development program, which began in 2013, the Company has participated in 41 horizontal wells for approximately$23.9 million through the fourth quarter of 2019 with an average of approximately 7% interest. During this same period the Company chose to retain an overriding royalty interest in an additional 61 horizontal wells. In 2019, the Company participated for an average 4.46% interest in 21 horizontal wells in Canadian,Grady , andKingfisher counties for a net cost of approximately$7 million . Seventeen of these were drilled and completed in 2019, and of these twelve were operated byEncana /Newfield. Four of the 21 wells were drilled but not yet been completed at year-end. Also during 2019, the Company retained an overriding royalty interest in nine wells that were completed by year-end, as well as in nine additional wells that are expected to be completed in 2020. 20
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Our horizontal activity inOklahoma is focused in Canadian,Grady ,Kingfisher ,Garfield ,Major , andGarvin counties where we have approximately 3,460 net acres. We believe this acreage has significant additional resource potential that could support the drilling of as many as 52 new horizontals based on an estimate of six wells per section: three in the Mississippian and three in theWoodford Shale . Should we choose to participate in future development, our share of the capital expenditures would be approximately$40 million at an average 10% ownership level; the Company will otherwise sell its rights for cash, or cash plus a royalty or working interest. In 2019, in theGulf Coast region ofTexas , we participated with Unit Petroleum in the successful recompletion of two wells in the Wilcox Formation of the Jazz field inPolk County, Texas . The Company has a 2.8125% working interest and a 3.768% net revenue interest in these wells and participated for approximately$45,000 . Also in 2019, the Company successfully recompleted a shallow well in theSegno field ofPolk County, Texas with a 72.5% working interest at an expense of approximately$50,000 .
RESULTS OF OPERATIONS
2020 and 2019 Compared
We report a net loss of$170 thousand ,$0.09 per share, for the three months endedMarch 2020 compared with net loss of$3.04 million ,$1.49 per share, for the same period of 2019. The current year net loss reflects decreases in oil, gas and NGLs sales due to lower commodity prices offset by an unrealized gain on derivatives. The significant components of income and expense are discussed below. Oil, gas and NGLs sales decreased$11.08 million , or 46.4% from$23.88 million for the three months endedMarch 31, 2019 to$12.8 million for the three months endedMarch 31, 2020 . Sales vary due to changes in volumes of production sold and realized commodity prices. Our realized prices decreased an average of$7.03 per barrel, or 13.3% on crude oil, decreased an average of$1.46 per mcf, or 61.7% on natural gas and decreased an average of$10.24 per barrel, or 51.1% on NGLs, during the three months endedMarch 31, 2020 from the same period in 2019. Our crude oil production decreased by 122,000 barrels, or 34.3% from 356,000 barrels for the first quarter 2019 to 234,000 barrels for the first quarter 2020. Our natural gas production decreased by 10,000 mcf, or 1.1% from 948,000 mcf for the first quarter 2019 to 938,000 mcf for the first quarter 2020. Our natural gas liquids production decreased by 15,000 barrels, or 10.6% from 142,000 barrels for the first quarter 2019 to 127,000 barrels for the first quarter 2020. The decrease in production volumes reflect the natural decline of our properties combined with the shut-in of high lifting cost properties as commodity prices decreased during the quarter. The following table summarizes the primary components of production volumes and average sales prices realized for the three months endedMarch 31, 2020 and 2019 (excluding realized gains and losses from derivatives). Three Months Ended March 31, Increase / Increase / 2020 2019 (Decrease) (Decrease) Barrels of Oil Produced 234,000 356,000 (122,000) (34.3 )% Average Price Received$ 45.77 $ 52.80 $ (7.03) (13.3 )% Oil Revenue (In 000's)$ 10,711 $ 18,798 $ (8,087) (43.0 )% Mcf of Gas Sold 938,000 948,000 (10,000) (1.1 )% Average Price Received$ 0.90 $ 2.36 $ (1.46) (61.7 )% Gas Revenue (In 000's)$ 846 $ 2,235 $ (1,389) (62.1 )% Barrels of Natural Gas Liquids Sold 127,000 142,000 (15,000) (10.6 )% Average Price Received$ 9.79 $ 20.02 $ (10.24) (51.1 )%
Natural Gas Liquids Revenue (In 000's)
(1,601) (56.3 )% Total Oil & Gas Revenue (In 000's)$ 12,800 $ 23,877 $ (11,077) (46.4 )% Realized net losses on derivative instruments include net gains of$0.19 million and$1.01 million on the settlements of natural gas and crude oil derivatives for the first quarter 2020, and net gains of$0.002 million and$0.089 million on the settlements of natural gas liquids and crude oil derivatives, and net losses on the settlements of natural gas derivatives, respectively for the first quarter 2019. 21
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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. Changes in market values in the first quarter of 2020 resulted in net unrealized gains of$6.25 million and$0.31 million associated with crude oil and natural gas contracts, respectively. Changes in market values in the first quarter of 2019 resulted in net unrealized losses of$5.738 million ,$0.005 million and$0.009 million associated with crude oil, natural gas and natural gas liquids contracts, respectively. Prices received for the three months endedMarch 31 , respectively, including the impact of derivatives were: 2020 2019 Oil Price$ 45.82 $ 53.09 Gas Price$ 0.90 $ 2.34 NGLS Price$ 9.79 $ 20.07 Field service income decreased$0.43 million or 9.1% for the first quarter 2020 to$4.3 million from$4.7 million for the first quarter 2019. This decrease is a combined result of decreased utilization and rates charged to customers as oil and gas prices declined during the quarter. Workover rig services, hot oil treatments, salt water hauling and disposal represent the bulk of our field service operations. Lease operating expensedecreased$1.73 million or 21.4% from$8.08 million for the first quarter 2019 to$6.34 million for the first quarter 2020. This decrease is primarily due to lower production taxes related to lower commodity prices. Field service expense decreased$0.12 million or 3.2% to$3.55 million for the first quarter 2020 from$3.67 million for the first quarter 2019. Field service expenses primarily consist of salaries and vehicle operating expenses which have decreased during the three months endedMarch 31, 2020 over the same period of 2019 related to decreased utilization of the equipment as oil and gas prices declined during the quarter. Depreciation, depletion, amortization and accretion on discounted liabilities decreased$1.03 million or 16.8% from$9.23 million for the first quarter 2019 to$8.2 million for the first quarter 2020 reflecting the reduced production rates in the first quarter of 2020. General and administrative expense increased$0.86 million or 12.5% from$6.88 million for the three months endedMarch 31, 2019 to$7.74 million for the three months endedMarch 31, 2020 . This increase in 2020 is primarily due to increases in employee wages and benefits. Interest expense decreased$0.32 million or 32.4% from$0.98 million for the first quarter 2019 to$0.66 million for the first quarter 2020. This decrease reflects the decrease in current borrowings under our revolving credit agreement.
Income tax benefit and expense for the
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 three months endedMarch 31, 2020 was$7.38 million . 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. 22
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Maintaining a strong balance sheet and ample liquidity are key components of our business strategy. For 2020, we will continue our focus on preserving financial flexibility and ample liquidity as we manage the risks facing our industry. Our 2020 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 ofFebruary 15, 2021 , providing for a credit facility totaling$300 million , with a borrowing base of$72 million . As ofJune 26, 2020 , the Company has$53.5 million in outstanding borrowings and$18.5 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 forJuly 2020 . 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 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 and put agreements for oil and natural gas.
2020 2021 2020 2021
Swap Agreements
Natural Gas (MMBTU) 180,000 951,000 $ 2.95 $ 2.41
Oil (barrels) 225,500 $ 58.43
2020 2021 2020 2021
Put Agreements
Natural Gas (MMBTU) 1,849,000 500,000 $ 2.25 $ 2.00
Oil (barrels) 95,400 66,000 $ 48.27 $ 35.00
On March 27, 2020 , President Trump signed into law the Coronavirus Aid, Relief,
and Economic Security Act (the "CARES Act"). The CARES Act, among other things,
includes provisions relating to refundable payroll tax credits, deferment of
employer side social security payments, net operating loss carryback periods,
alternative minimum tax credit refunds, modifications to the net interest
deduction limitations, increased limitations on qualified charitable
contributions, and technical corrections to tax depreciation methods for
qualified improvement property.
On March 25, 2020 , the SEC issued an Order under Section 36 of the Securities
Exchange Act of 1934 Modifying Exemptions From the Reporting and Proxy Delivery
Requirements for Public Companies, (Release No. 34-88465) (the "Order"), which
provides conditional relief to registrants subject to the reporting requirements
of Section 13(a) or 15(d) of the Securities Exchange Act of 1934 that are unable
to meet a filing deadline due to circumstances related to COVID-19.
We have experienced significant disruptions to our business and operations. In
particular, COVID-19restrictions have limited access to our corporate offices
and required our corporate personnel, including our legal and accounting staff.
The restrictions have resulted in limited access to the Company's financial
records and data and disrupted interactions among the personnel involved in the
completion of the Form 10-Q as of March 31, 2020 and for the quarter then ended
and slowing the Company's completion of its quarterly financial preparation of
the Form 10-Q.
As a result of the above, we filed a Form 8-K on May 8, 2020 taking advantage of
this relief and extended the deadline for the filing of this Form 10-Q by 45
days.
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Paycheck Protection Program Loans
DuringMay 2020 ,Prime Operating Company andEastern Oil Well Services Corporation , subsidiaries of the Company received loan proceeds in the amount of$1.28 million and$0.47 million , respectively, under the Paycheck Protection Program (the "PPP") of the CARES Act. The PPP Loans are evidenced by a promissory note in favor of the Lender, which bears interest at the rate of 1.00% per annum. No payments of principal or interest are due under the note until the date on which the amount of loan forgiveness (if any) under the CARES Act, which can be up to 10 months after the end of the related notes covered period (which is defined as 24 weeks after the date of the loan) (the "Deferral Period"). The note may be prepaid at any time prior to maturity with no prepayment penalties. Funds from the PPP Loans may be used only for payroll and related costs, costs used to continue group health care benefits, mortgage payments, rent, utilities, and interest on other debt obligations that were incurred prior toFebruary 15, 2020 (the "Qualifying Expenses"). Under the terms of the PPP Loans, certain amounts thereunder may be forgiven if they are used for Qualifying Expenses as described in and in compliance with the CARES Act. While the Company intends to use the PPP Loan proceeds exclusively for Qualifying Expenses, it is unclear and uncertain whether the conditions for forgiveness of the PPP Loans will be met under the current guidelines of the CARES Act. Accordingly, we cannot make any assurance that the Company will be eligible for forgiveness of the PPP Loans, in whole or in part. To the extent, if any, that any or all of the PPP loans are not forgiven, beginning one month following expiration of the Deferral Period, and continuing monthly until 24 months from the date of each applicable Note (the "Maturity Date"), the Company is obligated to make monthly payments of principal and interest to the Lender with respect to any unforgiven portion of the Note, in such equal amounts required to fully amortize the principal amount outstanding on such Note as of the last day of the applicable Deferral Period by the applicable Maturity Date. 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. 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. We participated in 18 gross (1.6 net) horizontal wells drilled and completed in 2019, all of which were producing at year-end. In addition, 14 gross (4.63 net) wells that had been completed at year-end 2018 and in which we had participated, were also brought on-line in 2019. Of the total 18 wells completed in 2019, three are located inWest Texas , while 13 are in our Oklahoma Scoop-Stack horizontal development program. The three wells drilled inWest Texas in 2019 added significantly to our reserve base, as these probable undeveloped locations were the initial test wells in intervals above the Middle Wolfcamp: one in the Wolfcamp "A", one in theJo Mill and one in the Lower Spraberry, and have proved up these reservoirs for the 1,300 acre block in which they were drilled. Our share of the cost of these three wells is approximately$9.2 million . Not only did these wells add proved developed reserves, but as a result, nine additional locations in these reservoirs were proven for horizontal development. Six of the nine horizontals were drilled as ofApril 15, 2020 . The successful development of these reservoirs has also proved-uplocations to be drilled on our nearby 2,600-acre block in which the Company holds between 14% and 56% interest. It is anticipated that development of as many as 54 additional horizontal wells on this 2,600-acre block will occur over the coming years. The cost of such development would be approximately$370.6 million with the Company's share being approximately$170.8 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 early 2020, as mentioned above, the Company participated in the drilling of six wells inUpton County, Texas , operated by Apache Corporation. These wells are expected to be completed in the fourth quarter of 2020 with a total anticipated investment of$19.4 million . Also inUpton County, Texas , in early 2020, we participated for 7.7% interest in the horizontal drilling of a well operated by Pioneer Natural Resources that is expected to be completed in the second quarter of 2020. Our total net expenditure for this well is estimated to be$580,400 . 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 focus of our future activity will be on the continued development of our resource's potential in theWest Texas horizontal drilling program as well as our Scoop-Stack horizontal drilling program acreage inOklahoma in order to maximize cash flow and return on investment. The Company maintains an acreage position of 19,910 gross (12,560 net) acres in thePermian Basin inWest Texas , primarily inReagan ,Upton ,Martin andMidland counties and we believe this acreage has significant resource potential in as many as 10 reservoirs, including benches of the Spraberry,Jo Mill , and Wolfcamp that support the potential drilling of as many as 180 additional horizontal wells. 24
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InOklahoma , the Company's horizontal activity is primarily focused in Canadian,Grady ,Kingfisher ,Garfield ,Major , andGarvin counties where we have approximately 3,460 net leasehold acres. We believe this acreage has significant additional resource potential that could support the drilling of as many as 52 new horizontal wells based on an estimate of six wells per section: three in the Mississippian and three in theWoodford Shale . Should we choose to participate in future development, our share of the capital expenditures would be approximately$40 million at an average 10% ownership level; the Company will otherwise 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 and 2019 was$0.71 million and$5.9 million , respectively. In the current price environment, the Company will suspend their stock repurchase program.
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