☒ | ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
2021
☐ | TRANSITION REPORT PURSUANT TO SECTION 13 or 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
ActSecurities registered pursuant to Section 12(b) of the Act: NoneAct:Common Stock, par value $.10 per share(Title of Class) (§Large Accelerated Filer ☐ Accelerated Filer ☐ ☐☒ Smaller Reporting Company ☒ Emerging growth company ☐
$37,001,831.
EXPLANATORY NOTE
This Amendment No. 1 to Form10-K amends the Annual Report on Form10-KTable of Primeenergy Resources Corporation for the year ended December 31, 2018, which was originally filed with the U.S. Securities and Exchange Commission on April 16, 2019 (the “Original10-K”) is being filed to amend Item 2. Properties and Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations of the Original10-K in order to correct drafting errors in certain data in price and production tables that were inadvertently included in the Original10-K. All other information contained in the original Form10-K remains unchanged.
The following items are included in this amendment:
PART I - ITEM 2. Properties
PART II - ITEM 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations
PART IV - ITEM 15 (b) Exhibits
In addition, as required by Rule12b-15 under the Securities Exchange Act of 1934, new certifications by our principal executive officer and principal financial officer are filed as exhibits to this Amendment No. 1. However, because no financial statements are contained within this Amendment, we are not including new certifications pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. This Amendment does not reflect events occurring after April 16, 2019, the date of the filing of our Original10-K, or modify or update those disclosures that may have been affected by subsequent events. Accordingly, this Amendment No. 1 should be read in conjunction with the Original10-K.
PART IV Item 2. 4114 28 28 35 35 Item 7. 36 37 103743 43 43 43 44 III Item 15. 164545 45 45 45 1746SIGNATURES 50 FINANCIAL STATEMENTS: F-1
Item 1. | BUSINESS. |
Oil Purchasers: | ||||
Apache Corporation | 48 | % | ||
Plains All American Inc. | 18 | % | ||
Gas Purchasers: | ||||
Apache Corporation | 52 | % | ||
Targa Pipeline Mid-Continent West Tex, LLC | 19 | % |
Item 1A. | RISK FACTORS. |
Item 1B. | UNRESOLVED STAFF COMMENTS. |
Item 2. |
PROPERTIES. |
Oklahoma.
2018 | 2017 | 2016 | ||||||||||||||||||||||
Gross | Net | Gross | Net | Gross | Net | |||||||||||||||||||
Exploratory: | ||||||||||||||||||||||||
Oil | — | — | — | — | — | — | ||||||||||||||||||
Gas | — | — | — | — | — | — | ||||||||||||||||||
Dry | — | — | — | — | — | — | ||||||||||||||||||
Development: | ||||||||||||||||||||||||
Oil | 28 | 6.1 | 26 | 6.3 | 27 | 3.6 | ||||||||||||||||||
Gas | — | — | — | — | — | — | ||||||||||||||||||
Dry | — | — | — | — | — | — | ||||||||||||||||||
Total: | ||||||||||||||||||||||||
Oil | 28 | 6.1 | 26 | 6.3 | 27 | 3.6 | ||||||||||||||||||
Gas | — | — | — | — | — | — | ||||||||||||||||||
Dry | — | — | — | — | — | — | ||||||||||||||||||
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28 | 6.1 | 26 | 6.3 | 27 | 3.6 | |||||||||||||||||||
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2021. In 2021, we participated in the completion of twelve horizontal wells.
2021 | 2020 | 2019 | ||||||||||||||||||||||
Gross | Net | Gross | Net | Gross | Net | |||||||||||||||||||
Exploratory: | ||||||||||||||||||||||||
Oil | — | — | — | — | — | — | ||||||||||||||||||
Gas | — | — | — | — | — | — | ||||||||||||||||||
Dry | — | — | — | — | — | — | ||||||||||||||||||
Development: | ||||||||||||||||||||||||
Oil | 12 | 4.61 | 1 | 0.1 | 18 | 1.6 | ||||||||||||||||||
Gas | — | — | — | — | — | — | ||||||||||||||||||
Dry | — | — | — | — | — | — | ||||||||||||||||||
Total: | ||||||||||||||||||||||||
Oil | 12 | 4.61 | 1 | 0.1 | 18 | 1.6 | ||||||||||||||||||
Gas | — | — | — | — | — | — | ||||||||||||||||||
Dry | — | — | — | — | — | — | ||||||||||||||||||
12 | 4.61 | 1 | 0.1 | 18 | 1.6 | |||||||||||||||||||
Gross | Net | |||||||
Producing wells(1): | ||||||||
Oil Wells | 1076 | 555 | ||||||
Gas Wells | 736 | 519 |
Gross | Net | |||||||
Producing wells (1) : | ||||||||
Oil Wells | 926 | 498 | ||||||
Gas Wells | 281 | 66 |
(1) | A gross well is a well in which a working interest is owned. A net well is the sum of the fractional revenue interests owned in gross wells. Wells are classified by their primary product. Some wells produce both oil and gas. |
multiplying the gross production volume of properties in which we have an interest by the percentage of the leasehold, mineral or royalty interest owned by us.
2018 | 2017 | 2016 | ||||||||||
Oil (barrels) | 1,187,000 | 1,004,000 | 670,000 | |||||||||
NGL (barrels) | 463,000 | 305,000 | 196,000 | |||||||||
Gas (Mcf) | 3,735,000 | 3,571,000 | 3,699,000 |
2021 | 2020 | 2019 | ||||||||||
Oil (barrels) | 738,000 | 726,996 | 1,242,000 | |||||||||
NGL (barrels) | 416,000 | 435,260 | 574,000 | |||||||||
Gas (Mcf) | 3,236,000 | 3,374,397 | 4,397,000 |
2018 | 2017 | 2016 | ||||||||||
Average sales price per barrel of oil | $ | 60.46 | $ | 49.85 | $ | 39.73 | ||||||
Average sales price per barrel of NGL | $ | 27.79 | $ | 23.27 | $ | 15.60 | ||||||
Average sales price per Mcf of natural gas | $ | 2.30 | $ | 2.73 | $ | 2.32 | ||||||
Average production costs per net equivalent barrel of oil(1) | $ | 13.12 | $ | 14.30 | $ | 17.13 |
2021 | 2020 | 2019 | ||||||||||
Average sales price per barrel of oil | $ | 68.39 | $ | 38.02 | $ | 55.04 | ||||||
Average sales price per barrel of NGL | $ | 26.97 | $ | 11.22 | $ | 15.87 | ||||||
Average sales price per Mcf of natural gas | $ | 3.53 | $ | 1.24 | $ | 1.49 | ||||||
Average production costs per net equivalent barrel of oil (1) | $ | 13.76 | $ | 12.25 | $ | 11.52 |
(1) | Net equivalent barrels are computed at a rate of 6 Mcf per barrel and costs exclude production taxes. |
2018 | 2017 | 2016 | ||||||||||
Average sales price per barrel of oil | $ | 57.39 | $ | 49.70 | $ | 39.73 | ||||||
Average sales price per barrel of NGL | $ | 27.40 | $ | 23.27 | $ | 15.60 | ||||||
Average sales price per Mcf of natural gas | $ | 2.23 | $ | 2.73 | $ | 2.33 |
2021 | 2020 | 2019 | ||||||||||
Average sales price per barrel of oil | $ | 64.04 | $ | 45.79 | $ | 53.58 | ||||||
Average sales price per barrel of NGL | $ | 26.97 | $ | 11.22 | $ | 16.49 | ||||||
Average sales price per Mcf of natural gas | $ | 2.97 | $ | 1.38 | $ | 1.51 |
Developed | Undeveloped | Total | ||||||||||||||||||||||
Gross | Net | Gross | Net | Gross | Net | |||||||||||||||||||
Leasehold acreage | 169,791 | 69,736 | — | — | 169,791 | 69,736 | ||||||||||||||||||
Mineral fee acreage | 1,640 | 117 | 19,257 | 417 | 20,897 | 534 | ||||||||||||||||||
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Total | 171,431 | 69,853 | 19,257 | 417 | 190,688 | 70,270 | ||||||||||||||||||
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Developed | Undeveloped | Total | ||||||||||||||||||||||
Gross | Net | Gross | Net | Gross | Net | |||||||||||||||||||
Leasehold acreage | 90,933 | 25,358 | — | — | 90,933 | 25,358 | ||||||||||||||||||
Mineral fee acreage | 1,640 | 117 | 19,257 | 417 | 20,897 | 534 | ||||||||||||||||||
Total | 92,573 | 25,475 | 19,257 | 417 | 111,830 | 25,892 | ||||||||||||||||||
2024.
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
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) | ||||||||||||||||||||||||||||||||||||
2016 | 3,107 | 1,265 | 13,001 | 6,539 | 643 | 159 | 2,003 | 1,135 | 3,750 | 1,424 | 15,004 | 7,674 | ||||||||||||||||||||||||||||||||||||
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 |
Reserve Category | ||||||||||||||||||||||||||||||||||||||||||||||||
Proved Developed | Proved Undeveloped | Total | ||||||||||||||||||||||||||||||||||||||||||||||
As of December 31, | Oil (MBbls) | NGLs (MBbls) | Gas (MMcf) | Total (MBoe) | Oil (MBbls) | NGLs (MBbls) | Gas (MMcf) | Total (MBoe) | Oil (MBbls) | NGLs (MBbls) | Gas (MMcf) | Total (MBoe) | ||||||||||||||||||||||||||||||||||||
2019 | 4,381 | 2,914 | 19,995 | 10,268 | 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 | ||||||||||||||||||||||||||||||||||||
2021 | 5,386 | 2,882 | 23,902 | 12,252 | — | — | — | — | 5,386 | 2,882 | 23,902 | 12,252 |
(a) | In computing total reserves on a barrels of oil equivalent (Boe) basis, gas is converted to oil based on its relative energy content at the rate of six Mcf of gas to one barrel of oil and NGLs are converted based upon volume; one barrel of natural gas liquids equals one barrel of oil. |
At December 31, 2016, we had undeveloped reserves of 1,135 Mboe, attributable to 20 wells that were all put on production in the first quarter of 2017. During 2017, 22 horizontal wells were drilled and completed in West Texas, two in Oklahoma, and one vertical well in the Gulf Coast of Texas.
At December 31, 2017 our reserve report included 779 MBoe of proved undeveloped reserves attributable to 22 horizontal wells that were all completed in 2018, and therefore, 100% of these reserves were converted to proved developed in the 2018year-end reserves report.
In 2018, the Company completed and put on production nine horizontal wells in West Texas and five horizontal wells in Oklahoma. The Company also increased reserves through overriding royalty interest in 18 new horizontal wells drilled by other operators, primarily in Oklahoma. An additional eight wells that were drilled and completed in 2018 in our West Texas horizontal development program were designated asShut-in atyear-end, and have been brought on production in February, 2019.
In the first quarter of 2019, in West Texas, we are actively participatingparticipated in two horizontal wells for 46% interest, as well as participating in a third horizontal well for 5.3% interest. Onethe initial three shallow horizontals on our Kashmir tract with one of each of these three wells will be completed in the Wolfcamp “A”, Jo Mill, and Lower Spraberry. The Company has 48% interest in two of these wells and 5.3% in one well. All three wells were brought on production in May of 2019.
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.
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 | ||||||||||||||||||||||||
2016 | $ | 56,467 | $ | 46,827 | $ | 18,114 | $ | 10,403 | $ | 74,581 | $ | 57,230 | $ | 4,993 | $ | 52,237 | ||||||||||||||||
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 |
Proved Developed | Proved Undeveloped | Total | ||||||||||||||||||||||||||||||
As of December 31, | Future Net Revenue | Present Value 10 Of Future Net Revenue | Future Net Revenue | Present Value 10 Of Future Net Revenue | Future Net Revenue | Present Value 10 Of Future Net Revenue | Present Value 10 Of Future Income Taxes | Standardized Measure of Discounted Cash flow | ||||||||||||||||||||||||
2019 | $ | 116,592 | $ | 82,155 | $ | 42,700 | $ | 17,876 | $ | 159,292 | $ | 100,031 | $ | 18,419 | $ | 81,612 | ||||||||||||||||
2020 | $ | 43,886 | $ | 34,717 | $ | 37,346 | $ | 21,823 | $ | 81,232 | $ | 56,539 | $ | 14,920 | $ | 41,619 | ||||||||||||||||
2021 | $ | 275,227 | $ | 171,906 | $ | — | $ | — | $ | 275,227 | $ | 171,906 | $ | 36,100 | $ | 135,806 |
prices, based on the NYMEX first of the month average price, were $65.56$66.56 per barrel in 20182021 as compared to $51.34$39.57 per barrel in 2017,2020, and $42.75$55.69 per barrel in 2016.2019. Since January 1, 2019,2021, we have not filed any estimates of our oil and gas reserves with, nor were any such estimates included in any reports to, any federal authority or agency, other than the Securities and Exchange Commission.
Appalachian | Gulf Coast | Mid- Continent | West Texas | Other | Total | |||||||||||||||||||
Proved Reserves as of December 31, 2018 (MBoe) | ||||||||||||||||||||||||
Developed | 559 | 814 | 2,839 | 8,401 | 8 | 12,622 | ||||||||||||||||||
Undeveloped | — | — | 43 | — | — | 43 | ||||||||||||||||||
Total | 559 | 814 | 2,882 | 8,401 | 8 | 12,665 | ||||||||||||||||||
Average Daily Production (Boe per day) | 244 | 572 | 977 | 4,248 | 7 | 6,048 | ||||||||||||||||||
Gross Productive Wells (Working Interest and ORRI Wells) | 547 | 293 | 580 | 558 | 105 | 2,083 | ||||||||||||||||||
Gross Productive Wells (Working Interest Only) | 500 | 263 | 430 | 519 | 45 | 1,757 | ||||||||||||||||||
Net Productive Wells (Working Interest Only) | 469 | 164 | 227 | 256 | 4 | 1,120 | ||||||||||||||||||
Gross Operated Productive Wells | 476 | 211 | 243 | 354 | — | 1,284 | ||||||||||||||||||
Gross Operated Water Disposal, Injection and Supply wells | 1 | 9 | 67 | 7 | — | 84 |
2021.
Gulf Coast | Mid- Continent | West Texas | Other | Total | ||||||||||||||||
Proved Reserves as of December 31, 2021 (MBoe) | ||||||||||||||||||||
Developed | 906 | 2,383 | 8,957 | 6 | 12,252 | |||||||||||||||
Undeveloped | — | — | — | — | — | |||||||||||||||
Total | 906 | 2,383 | 8,957 | 6 | 12,252 | |||||||||||||||
Average Net Daily Production (Boe per day) | 336 | 747 | 2,878 | 3 | 3,964 | |||||||||||||||
Gross Productive Wells (Working Interest and ORRI Wells) | 207 | 549 | 576 | 200 | 1,532 | |||||||||||||||
Gross Productive Wells (Working Interest Only) | 189 | 400 | 530 | 88 | 1,207 | |||||||||||||||
Net Productive Wells (Working Interest Only) | 105 | 189 | 263 | 6 | 564 | |||||||||||||||
Gross Operated Productive Wells | 137 | 195 | 321 | — | 653 | |||||||||||||||
Gross Operated Water Disposal, Injection and Supply wells | 7 | 44 | 6 | — | 57 |
Appalachian Region
Our Appalachian activities are concentrated primarily in West Virginia. This region is managed from our office in Charleston, West Virginia. Our assets in this region include a large acreage position and a high concentration of wells. At December 31, 2018, we had interest in 500 wells (469 net), of which 477 wells are operated. There are multiple producing intervals that include the Big Lime, Injun, Blue Monday, Weir, Berea, Gordon and Devonian Shale formations at depths primarily ranging from 1,600 to 5,600 feet. Average net daily production in 2018 was 244 Boe. While natural gas production volumes from Appalachian reservoirs are relatively low on aper-well basis compared to other areas of the United States, the productive life of Appalachian reserves is relatively long. At December 31, 2018, we had 559 MBoe of proved developed reserves (substantially all natural gas) in the Appalachian region, constituting 4% of our total proved reserves. We maintain an acreage position of over 40,200 gross (39,700 net) acres in this region, primarily in Calhoun, Clay, and Roane 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 of March 31, 2019, 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.
220 137 wells are operated by us. Average net daily production in 2018our Gulf Coast Region in 2021 was 572336 Boe. At December 31, 2018,2021, we had 925906 MBoe of proved reserves in the Gulf Coast region, which represented 6%7% of our total proved reserves. We maintain an acreage position of over 12,70011,500 gross (5,120(3,967 net) acres in this region,
Item 3. | LEGAL PROCEEDINGS. |
Item 4. | MINE SAFETY DISCLOSURES. |
Item 5. | MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES. |
High | Low | |||||||
2021 | ||||||||
First Quarter | $ | 98.00 | $ | 34.33 | ||||
Second Quarter | 53.72 | 39.89 | ||||||
Third Quarter | 73.80 | 45.20 | ||||||
Fourth Quarter | 71.71 | 58.50 | ||||||
2020 | ||||||||
First Quarter | $ | 154.38 | $ | 47.68 | ||||
Second Quarter | 110.79 | 49.70 | ||||||
Third Quarter | 79.13 | 62.60 | ||||||
Fourth Quarter | 71.80 | 42.39 |
2021 Month | Number of Shares | Average Price Paid per share | Maximum Number of Shares that May Yet Be Purchased Under The Program at Month-End | |||||||||
January | — | $ | — | 147,721 | ||||||||
February | — | — | 147,721 | |||||||||
March | — | — | 147,721 | |||||||||
April | — | — | 147,721 | |||||||||
May | — | — | 147,721 | |||||||||
June | — | — | 147,721 | |||||||||
July | — | — | 147,721 |
2021 Month | Number of Shares | Average Price Paid per share | Maximum Number of Shares that May Yet Be Purchased Under The Program at Month-End | |||||||||
August | — | — | 147,721 | |||||||||
September | — | — | 147,721 | |||||||||
October | — | — | 147,721 | |||||||||
November | — | — | 147,721 | |||||||||
December | 2,100 | 69.04 | 145,621 | |||||||||
Total / Average | 2,100 | $ | 69.04 | |||||||||
Item 6. | SELECTED FINANCIAL DATA |
Item 7. |
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS |
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.
Volumes | Prices | |||||||||||||||
2019 | 2020 | 2019 | 2020 | |||||||||||||
Natural Gas (MMBTU) | 749,000 | 180,000 | $ | 2.93 | $ | 2.95 | ||||||||||
Natural Gas Liquids (barrels) | 60,000 | — | $ | 21.66 | — | |||||||||||
Oil (barrels) | 490,100 | 225,500 | $ | 53.35 | $ | 58.43 |
2022 | 2023 | 2022 | 2023 | |||||||||||||
Swap Agreements | ||||||||||||||||
Natural Gas (MMBTU) | 1,528,000 | 377,000 | $ | 3.15 | $ | 3.87 | ||||||||||
Oil (barrels) | 530,600 | 114,200 | $ | 66.20 | $ | 74.07 |
We participated in 28 gross (6.1 net) horizontal wells drilled and completed in 2018; 14 of these were producing atyear-end while the remaining 14 wells were categorized asshut-in and started producing in the first quarter of 2019. Of the total 28 wells, 15 are in our West Texas horizontal drilling program, while 13 are in our Oklahoma Scoop-Stack horizontal development program. In addition, the Company participated in the drilling of three Probable Undeveloped horizontal wells in Upton County, Texas targeting pay intervals above the Middle Wolfcamp: one in the Wolfcamp “A”, one in the Jo Mill and one in the Lower Spraberry. These wells are expected to be in production during the second quarter of 2019. These are important tests of the economic viability of the target reservoirs, both for the 1,300 acrenearby
of such development would be approximately $748 million with the Company’s share being approximately $284$170 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 the first quarter
2022.
revolving credit facility.
level; the Company will otherwise sell its rights for cash, or cash plus a royalty or working interest.
AsCompany to reduce its bank debt to $9 million, as of March 2019,31, 2022, with the Company has $464 thousand outstanding on our equipment financing facilities which are secured by substantially allright to borrow up to $50 million under its current revolving line of our field service equipment. credit.
2022.
2018
properties slightly offset by new wells placed in production.
Twelve months ended December 31, | Increase / (Decrease) | Increase / (Decrease) | ||||||||||||||
2018 | 2017 | |||||||||||||||
Barrels of Oil Produced | 1,187,000 | 1,004,000 | 183,000 | 18.2 | % | |||||||||||
Average Price Received | $ | 60.46 | $ | 49.85 | $ | 10.61 | 21.3 | % | ||||||||
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Oil Revenue (In 000’s) | $ | 71,766 | $ | 50,041 | $ | 21,725 | 43.4 | % | ||||||||
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Mcf of Gas Sold | 3,735,000 | 3,571,000 | 164,000 | 4.6 | % | |||||||||||
Average Price Received | $ | 2.30 | $ | 2.73 | $ | (0.43 | ) | (15.7 | )% | |||||||
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Gas Revenue (In 000’s) | $ | 8,590 | $ | 9,745 | $ | (1,155 | ) | (11.9 | )% | |||||||
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Barrels of Natural Gas Liquids Sold | 463,000 | 305,000 | 158,000 | 51.8 | % | |||||||||||
Average Price Received | $ | 27.79 | $ | 23.27 | $ | 4.53 | 19.5 | % | ||||||||
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Natural Gas Liquids Revenue (In 000’s) | $ | 12,859 | $ | 7,097 | $ | 5,762 | 81.2 | % | ||||||||
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Total Oil & Gas Revenue (In 000’s) | $ | 93,215 | $ | 66,883 | $ | 26,332 | 39.4 | % |
Twelve months ended December 31, | Increase / (Decrease) | Increase / (Decrease) | ||||||||||||||
2021 | 2020 | |||||||||||||||
Barrels of Oil Produced | 738,000 | 733,000 | 5,000 | 0.68 | % | |||||||||||
Average Price Received | $ | 68.39 | $ | 38.02 | $ | 30.38 | 79.91 | % | ||||||||
Oil Revenue (In 000’s) | $ | 50,474 | $ | 27,865 | $ | 22,609 | 81.14 | % | ||||||||
Mcf of Gas Sold | 3,236,000 | 3,381,000 | (145,000 | ) | (4.29 | )% | ||||||||||
Average Price Received | $ | 3.53 | $ | 1.24 | $ | 2.29 | 184.25 | % | ||||||||
Gas Revenue (In 000’s) | $ | 11,432 | $ | 4,202 | $ | 7,230 | 172.06 | % | ||||||||
Barrels of Natural Gas Liquids Sold | 416,000 | 437,000 | (21,000 | ) | (4.85 | )% | ||||||||||
Average Price Received | $ | 26.97 | $ | 11.22 | $ | 15.75 | 140.36 | % | ||||||||
Natural Gas Liquids Revenue (In 000’s) | $ | 11,220 | $ | 4,906 | $ | 6,314 | 128.70 | % | ||||||||
Total Oil & Gas Revenue (In 000’s) | $ | 73,126 | $ | 36,973 | $ | 36,153 | 97.78 | % |
Twelve months ended December 31, | ||||||||
2018 | 2017 | |||||||
Oil derivatives – realized gains (losses) | $ | (3,642 | ) | $ | (146 | ) | ||
Oil derivatives – unrealized gains (losses) | 5,600 | (1,720 | ) | |||||
|
|
|
| |||||
Total gains (losses) on oil derivatives | $ | 1,958 | $ | (1,866 | ) | |||
Natural gas derivatives – realized gains (losses) | $ | (278 | ) | $ | (9 | ) | ||
Natural gas derivatives – unrealized gains (losses) | (394 | ) | 2,267 | |||||
|
|
|
| |||||
Total gains (losses) on natural gas derivatives | $ | (672 | ) | $ | 2,258 | |||
NGL derivatives – realized (losses) | $ | (175 | ) | — | ||||
NGL derivatives – unrealized gains (losses) | 124 | — | ||||||
|
|
|
| |||||
Total gains (losses) on NGL derivatives | (51 | ) | — | |||||
|
|
|
| |||||
Total gains (losses) on oil, natural gas and NGL derivatives | $ | 1,235 | $ | 392 | ||||
|
|
|
|
Twelve months ended December 31, | ||||||||
2021 | 2020 | |||||||
Oil derivatives – realized (losses) gains | $ | (3,212 | ) | $ | 5,697 | |||
Oil derivatives – unrealized (losses) gains | (4,055 | ) | 161 | |||||
Total (losses) gains on oil derivatives | $ | (7,267 | ) | $ | 5,858 | |||
Natural gas derivatives – realized (losses) gains | (1,833 | ) | 476 | |||||
Natural gas derivatives – unrealized (losses) | (859 | ) | (351 | ) | ||||
Total (losses) gains on natural gas derivatives | $ | (2,692 | ) | $ | 125 | |||
Total (losses) gains on oil and natural gas | $ | (9,959 | ) | $ | 5,983 | |||
2018 | 2017 | Increase / (Decrease) | Increase / (Decrease) | |||||||||||||
Oil Price | $ | 57.39 | $ | 49.70 | $ | 7.70 | 15.5 | % | ||||||||
Gas Price | $ | 2.23 | $ | 2.73 | $ | (0.50 | ) | (18.4 | )% | |||||||
NGL Price | $ | 27.40 | $ | 23.27 | $ | 4.13 | 17.7 | % |
2021 | 2020 | Increase / (Decrease) | Increase / (Decrease) | |||||||||||||
Oil Price | $ | 64.04 | $ | 45.79 | $ | 18.25 | 39.9 | % | ||||||||
Gas Price | $ | 2.97 | $ | 1.38 | $ | 1.58 | 114.4 | % | ||||||||
NGL Price | $ | 26.97 | $ | 11.22 | $ | 15.75 | 140.4 | % |
field service operations.
higher commodity prices.
properties.
compensation.
in 2020, also included the sale of marginal wells in West Virginia.
Item 7A. | QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK. |
Item 8. | FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA. |
Item 9. | CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE. |
Item 9A. | CONTROLS AND PROCEDURES. |
Item 9B. | OTHER INFORMATION. |
Item 10. | DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE. |
Item 11. | EXECUTIVE COMPENSATION. |
Item 12. | SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS. |
Item 13. | CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE. |
Item |
PRINCIPAL ACCOUNTANT FEES AND SERVICES. |
Item 15. | EXHIBITS AND FINANCIAL STATEMENT SCHEDULES. |
1. | Financial statements (Index to Consolidated Financial Statements at page F-1 of this Report) |
2. | Financial Statement Schedules (Index to Consolidated Financial Statements – Supplementary Information at page F-1 of this Report) |
3. | Exhibits: |
48
Exhibit No. | ||
101.INS | Inline XBRL (eXtensible Business Reporting Language) Instance Document (filed herewith) | |
101.SCH | Inline XBRL Taxonomy Extension Schema Document (filed herewith) | |
101.CAL | Inline XBRL Taxonomy Extension Calculation Linkbase Document (filed herewith) | |
101.DEF | Inline XBRL Taxonomy Extension Definition Linkbase Document (filed herewith) | |
101.LAB | Inline XBRL Taxonomy Extension Label Linkbase Document (filed herewith) | |
101.PRE | Inline XBRL Taxonomy Extension Presentation Linkbase Document (filed herewith) | |
104 | Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101) |
PrimeEnergy Resources Corporation | ||
By: | /s/ Charles E. Drimal, Jr. | |
Charles E. Drimal, Jr. | ||
Chairman, Chief Executive Officer and President |
/s/ Charles E. Drimal, Jr. Charles E. Drimal, Jr. | Chairman, Chief Executive Officer and President; The Principal Executive Officer | |
/s/ Beverly A. Cummings Beverly A. Cummings | Director, Executive Vice President and Treasurer; The Principal Financial Officer |
/s/ Clint Hurt Clint Hurt | Director | /s/ Thomas S. T. Gimbel Thomas S. T. Gimbel | Director | |||
/s/ H. Gifford Fong H. Gifford Fong | Director |
F-2 | ||||
Financial Statements | ||||
F-5 | ||||
F-6 | ||||
F-7 | ||||
F-8 | ||||
F-9 | ||||
Supplementary Information: | ||||
F-22 | ||||
F-22 | ||||
F-22 | ||||
F-23 | ||||
F-24 | ||||
F-24 | ||||
F-25 |
Depreciation, Depletion and Amortization and Impairment of Property and Equipment | ||
Description of the Matter | At December 31, 2021, the carrying value of the Company’s property and equipment was $184.7 million, and depreciation, depletion and amortization (DD&A) expense was $26.3 million for the year then ended. As described in Note 1, the Company follows the “successful efforts” method of accounting for its oil and gas properties. Under the “successful efforts” method, costs of acquiring undeveloped oil and gas leasehold acreage, including lease bonuses, brokers’ fees and other related costs, are capitalized. Provisions for impairment of undeveloped oil and gas leases are based on periodic evaluations. Annual lease rentals and exploration expenses, including geological and geophysical expenses and exploratory dry hole costs, are charged against income as incurred. Costs of drilling and equipping productive wells, including development of dry holes and related production facilities, are capitalized. All other property and equipment are carried at cost. Depreciation and depletion of oil and gas production equipment and properties are determined under the unit-of-production method based on estimated proved developed recoverable oil and gas reserves. Depreciation of all other equipment is determined under the straight-line method using various rates based on useful lives generally ranging from 5 to 10 years. The cost of assets and related accumulated depreciation is removed from the accounts when such assets are disposed of, and any related gains or losses are reflected in current earnings. Interest costs related to financing major oil and gas projects in progress are capitalized until the projects are evaluated or until the projects are substantially complete and ready for their intended use if the projects are evaluated and successful. The Company reviews long-lived assets, including oil and gas properties, for impairment whenever events or changes in circumstances indicate that the carrying amounts may not be recovered. If the carrying amounts are not expected to be recovered by undiscounted cash flows, the assets are impaired, and an impairment loss is recorded. The amount of impairment is based on the estimated fair value of the assets determined by discounting anticipated future net cash flows. Proved oil and gas reserves directly impact financial accounting estimates, including depreciation, depletion and amortization. Proved reserves represent estimated quantities of natural gas, crude oil, condensate, and natural gas liquids that geological and engineering data demonstrate, with reasonable certainty, to be recoverable in future years from known reservoirs under economic and operating conditions existing at the time the estimates were made. The process of estimating quantities of proved oil and gas reserves is very complex, requiring significant subjective decisions in the evaluation of all available geological, engineering and economic data for each reservoir. The data for a given reservoir may also change substantially over time as a result of numerous factors including, but not limited to, additional development activity, evolving production history and continual reassessment of the viability of production under varying economic conditions. Consequently, material revisions (upward or downward) to existing reserve estimates may occur from time to time. Estimates of oil and gas reserves, as determined by independent petroleum engineers, are continually subject to revision based on price, production history and other factors. Depletion expense, which is computed based on the units of production method, could be significantly impacted by changes in such estimates. Additionally, U.S. generally accepted accounting principles require that if the expected future undiscounted cash flows from an asset are less than its carrying cost, that asset must be written down to its fair market value. As the fair market value of an oil and gas property will usually be significantly less than the total undiscounted future net revenues expected from that asset, slight changes in the estimates used to determine future net revenues from an asset could lead to the necessity of recording a significant impairment of that asset. Auditing the Company’s DD&A and impairment calculations is complex because of the use of independent petroleum engineers and the evaluation of management’s determination of the inputs described above used by the engineers in estimating oil and gas reserves. |
How We Addressed the Matter in Our Audit | We obtained an understanding and evaluated the design of the Company’s controls over its process to calculate DD&A and impairment, including management’s controls over the completeness and accuracy of the financial data utilized by the engineers in estimating oil and gas reserves. Our audit procedures included, among others, evaluating the professional qualifications and objectivity of the Company’s independent petroleum engineers responsible for the preparation of the proved oil and gas reserve estimates for select properties. In addition, we compared the Company’s recent production with its reserve estimates for properties that have significant production or significant reserve quantities and inquired of disproportionate ratios that did not align with our expectations. We also tested the mathematical accuracy of the DD&A and impairment calculations, including comparing the oil and gas reserve amounts used in the calculations to the Company’s reserve reports. | |
Accounting for Asset Retirement Obligations | ||
Description of the Matter | At December 31, 2021, the asset retirement obligation (ARO) balance totaled $14.3 million. As further described in Note 1, the Company’s ARO primarily represents the estimated present value of the amount the Company will incur to plug, abandon, and remediate producing properties at the end of their productive lives, in accordance with applicable state laws. The Company determined its asset retirement obligation by calculating the present value of estimated cash flows related to the liability. The asset retirement obligation is recorded as a liability at its estimated present value at its inception, with an offsetting increase to producing properties. Periodic accretion of discount of the estimated liability is recorded as an expense in the statement of operations. The Company’s liability is determined using significant assumptions, including current estimates of plugging and abandonment costs, annual inflation of these costs, the productive life of wells and a risk-adjusted interest rate. Changes in any of these assumptions can result in significant revisions to the estimated asset retirement obligation. Revisions to the asset retirement obligation are recorded with an offsetting change to producing properties, resulting in prospective changes to depreciation, depletion and amortization expense and accretion of discount. Because of the subjectivity of assumptions and the relatively long life of most of the Company’s wells, the costs to ultimately retire the wells may vary significantly from previous estimates. Auditing the Company’s ARO is complex and highly judgmental because of the significant estimation by management in determining the obligation. In particular, the estimate was sensitive to significant subjective assumptions such as retirement cost estimates and the estimated timing of settlements, which are both affected by expectations about future market and economic conditions. | |
How We Addressed the Matter in Our Audit | We obtained an understanding and evaluated the design of the Company’s internal controls over its ARO estimation process, including management’s review of the significant assumptions that have a material effect on the determination of the obligations. To test the ARO for the Company, our audit procedures included, among others, assessing the significant assumptions and inputs used in the valuation, such as retirement cost estimates and timing of settlement assumptions. Additionally, we compared the ARO against historical results, reviewed the reasonableness of the discount rate utilized in the estimate, considered the reasonableness of the current and long-term portion of the obligation by comparing the accretion expense trends, and considered the completeness of the properties included in the estimate by comparing to the Company’s reserve reports. |
As of December 31, | ||||||||
2021 | 2020 | |||||||
ASSETS | ||||||||
Current Assets | ||||||||
Cash and cash equivalents | $ | 10,347 | $ | 996 | ||||
Accounts receivable, net | 14,208 | 7,221 | ||||||
Prepaid obligations | 733 | 590 | ||||||
Other current assets | 40 | 104 | ||||||
Total Current Assets | 25,328 | 8,911 | ||||||
Property and Equipment | ||||||||
Oil and gas properties at cost | 539,484 | 520,488 | ||||||
Less: Accumulated depletion and depreciation | (359,742 | ) | (335,390 | ) | ||||
179,742 | 185,098 | |||||||
Field and office equipment at cost | 27,080 | 26,797 | ||||||
Less: Accumulated depreciation | (22,159 | ) | (20,842 | ) | ||||
4,921 | 5,955 | |||||||
Total Property and Equipment, Net | 184,663 | 191,053 | ||||||
Derivative asset long-term and other assets | 923 | 520 | ||||||
Total Assets | $ | 210,914 | $ | 200,484 | ||||
LIABILITIES AND EQUITY | ||||||||
Current Liabilities | ||||||||
Accounts payable | $ | 7,282 | $ | 5,217 | ||||
Accrued liabilities | 7,821 | 6,787 | ||||||
Due to related parties | 52 | 38 | ||||||
Current portion of long-term debt | — | 487 | ||||||
Current portion of asset retirement and other long-term obligations | 1,630 | 867 | ||||||
Derivative liability short-term | 4,935 | 724 | ||||||
Total Current Liabilities | 21,720 | 14,120 | ||||||
Long-Term Bank Debt | 36,000 | 38,267 | ||||||
Asset Retirement Obligations | 13,222 | 12,891 | ||||||
Derivative Liability Long-Term | 650 | 44 | ||||||
Deferred Income Taxes | 38,743 | 36,367 | ||||||
Other Long-Term Obligations | 1,488 | 797 | ||||||
Total Liabilities | 111,823 | 102,486 | ||||||
Commitments and Contingencies | ||||||||
Equity | ||||||||
Common stock, $.10 par value; 2021 and 2020: Authorized: 2,810,000 shares, outstanding 2021: 1,992,077 shares; outstanding 2020: 1,994,177 shares . | 281 | 281 | ||||||
Paid-in capital | 7,555 | 7,541 | ||||||
Retained earnings | 128,902 | 126,804 | ||||||
Treasury stock, at cost; 2021: 817,923 shares; 2020: 815,823 | (37,647 | ) | (37,502 | ) | ||||
Total Stockholders’ Equity – PrimeEnergy | 99,091 | 97,124 | ||||||
Non-controlling interest | 0 | 874 | ||||||
Total Equity | 99,091 | 97,998 | ||||||
Total Liabilities and Equity | $ | 210,914 | $ | 200,484 | ||||
For the Year Ended December 31, | ||||||||
2021 | 2020 | |||||||
Revenues | ||||||||
Oil sales | $ | 50,474 | $ | 27,865 | ||||
Natural gas sales | 11,432 | 4,202 | ||||||
Natural gas liquids sales | 11,220 | 4,906 | ||||||
Realized gain (loss) on derivative instruments, net | (5,045 | ) | 6,173 | |||||
Field service income | 11,806 | 11,120 | ||||||
Administrative overhead fees | 4,611 | 4,163 | ||||||
Unrealized (loss) on derivative instruments | (4,914 | ) | (190 | ) | ||||
Other income | 29 | 182 | ||||||
Total Revenues | 79,613 | 58,421 | ||||||
Costs and Expenses | ||||||||
Lease operating expense | 27,804 | 23,028 | ||||||
Field service expense | 11,580 | 9,006 | ||||||
Depreciation, depletion, amortization and accretion on discounted liabilities | 26,325 | 28,176 | ||||||
General and administrative expense | 10,426 | 15,027 | ||||||
Total Costs and Expenses | 76,135 | 75,237 | ||||||
Gain on Sale and Exchange of Assets | 1,478 | 15,836 | ||||||
Income (Loss) from Operations | 4,956 | (980 | ) | |||||
Other Income and Expenses | ||||||||
Less: Interest expense | (2,007 | ) | (1,902 | ) | ||||
Add: Other income | — | 2 | ||||||
Add: PPP Loan Forgiveness | 1,693 | — | ||||||
Income (Loss) Before Provision for (Benefit from) Income Taxes | 4,642 | (2,880 | ) | |||||
Provision (Benefit from) Income Taxes | 2,516 | (517 | ) | |||||
Net Income (Loss) | 2,126 | (2,363 | ) | |||||
Less: Net Income (Loss) Attributable to Non-Controlling Interest | 28 | (47 | ) | |||||
Net Income (Loss) Attributable to PrimeEnergy | $ | 2,098 | $ | (2,316 | ) | |||
Basic Income (Loss) Per Common Share | $ | 1.05 | $ | (1.16 | ) | |||
Diluted Income (Loss) Per Common Share | $ | 0.76 | $ | (1.16 | ) | |||
Shares Outstanding | Common Stock | Additional Paid-In Capital | Retained Earnings | Treasury Stock | Total Stockholders’ Equity – PrimeEnergy | Non- Controlling Interest | Total Equity | |||||||||||||||||||||||||
Balance at December 31, 2019 | 1,998,978 | $ | 281 | $ | 7,505 | $ | 129,120 | $ | (36,792 | ) | $ | 100,114 | $ | 3,249 | $ | 103,363 | ||||||||||||||||
Purchase 4,801 shares of common stock | (4,801 | ) | — | — | — | (710 | ) | (710 | ) | — | (710 | ) | ||||||||||||||||||||
Net loss | — | — | — | (2,316 | ) | — | (2,316 | ) | (47 | ) | (2,363 | ) | ||||||||||||||||||||
Purchase of non-controlling interest | — | — | 36 | — | — | 36 | (58 | ) | (22 | ) | ||||||||||||||||||||||
Distributions to non-controlling interest | — | — | — | — | — | — | (2,270 | ) | (2,270 | ) | ||||||||||||||||||||||
Balance at December 31, 2020 | 1,994,177 | $ | 281 | $ | 7,541 | $ | 126,804 | $ | (37,502 | ) | $ | 97,124 | $ | 874 | $ | 97,998 | ||||||||||||||||
Purchase 2,100 shares of common stock | (2,100 | ) | — | — | — | (145 | ) | (145 | ) | — | (145 | ) | ||||||||||||||||||||
Net Income | — | — | — | 2,098 | — | 2,098 | 28 | 2,126 | ||||||||||||||||||||||||
Purchase of non-controlling interest | — | — | 14 | 0 | — | 14 | (58 | ) | (44 | ) | ||||||||||||||||||||||
Distributions to non-controlling interest | — | — | — | 0 | — | — | (844 | ) | (844 | ) | ||||||||||||||||||||||
Balance at December 31, 2021 | 1,992,077 | $ | 281 | $ | 7,555 | $ | 128,902 | $ | (37,647 | ) | $ | 99,091 | $ | 0 | $ | 99,091 | ||||||||||||||||
For the Year Ended December 31, | ||||||||
2021 | 2020 | |||||||
Cash Flows from Operating Activities: | ||||||||
Net Income (Loss) | $ | 2,126 | $ | (2,363 | ) | |||
Adjustments to reconcile net income (loss) to net cash provided by operating activities: | ||||||||
Depreciation, depletion, amortization and accretion on discounted liabilities | 26,325 | 28,176 | ||||||
Gain on sale of properties | (1,478 | ) | (15,836 | ) | ||||
Unrealized loss (gain) on derivative instruments | 4,914 | 190 | ||||||
PPP Loan forgiveness | (1.693 | ) | — | |||||
Provision for deferred income taxes | 2,376 | 443 | ||||||
Changes in assets and liabilities: | ||||||||
Accounts receivable | (6,987 | ) | 7,139 | |||||
Due to related parties | 14 | 38 | ||||||
Prepaid expenses and other assets | (79 | ) | 58 | |||||
Accounts payable | 2,065 | (1,417 | ) | |||||
Accrued liabilities | 1,034 | (49 | ) | |||||
Net Cash Provided by Operating Activities | 28,617 | 16,379 | ||||||
Cash Flows from Investing Activities: | ||||||||
Capital expenditures, including exploration expense | (20,726 | ) | (10,523 | ) | ||||
Proceeds from sale of properties and equipment | 1,478 | 10,862 | ||||||
Net Cash (Used in) provided by Investing Activities | (19,248 | ) | 339 | |||||
Cash Flows from Financing Activities: | ||||||||
Purchase of stock for treasury | (145 | ) | (710 | ) | ||||
Purchase of non-controlling interests | (676 | ) | (742 | ) | ||||
Increase in long-term bank debt and other long-term obligations | 11,209 | 6,755 | ||||||
Repayment of long-term bank debt and other long-term obligations | (10,209 | ) | (21,983 | ) | ||||
Distribution to non-controlling interest | (197 | ) | (57 | ) | ||||
Net Cash (used in) Financing Activities | (18 | ) | (16,737 | ) | ||||
Net Increase (Decrease) in Cash and Cash Equivalents | 9,351 | (19 | ) | |||||
Cash and Cash Equivalents at the Beginning of the Year | 996 | 1,015 | ||||||
Cash and Cash Equivalents at the End of the Year | $ | 10,347 | $ | 996 | ||||
Supplemental Disclosures: | ||||||||
Income taxes paid during the year | $ | 343 | $ | 1 | ||||
Interest paid during the year | $ | 1,957 | $ | 2,052 | ||||
Non-Cash Disclosures: | ||||||||
Purchase of non-controlling interest | $ | 14 | $ | 36 | ||||
Distribution of non-controlling interest in liquidated partnerships | $ | 647 | $ | 1,550 |
December 31, | ||||||||
(Thousands of dollars) | 2021 | 2020 | ||||||
Joint interest billings | $ | 1,902 | $ | 2,475 | ||||
Trade receivables | 1,429 | 1,073 | ||||||
Oil and gas sales | 11,154 | 3,469 | ||||||
Other | 94 | 802 | ||||||
14,579 | 7,819 | |||||||
Less: Allowance for doubtful accounts | (371 | ) | (598 | ) | ||||
Total | $ | 14,208 | $ | 7,221 | ||||
December 31, | ||||||||
(Thousands of dollars) | 2021 | 2020 | ||||||
Trade | $ | 2,390 | $ | 876 | ||||
Royalty and other owners | 2,802 | 3,569 | ||||||
Partner advances | 1,209 | 193 | ||||||
Other | 881 | 579 | ||||||
�� | ||||||||
Total | $ | 7,282 | $ | 5,217 | ||||
December 31, | ||||||||
(Thousands of dollars) | 2021 | 2020 | ||||||
Compensation and related expenses | $ | 3,919 | $ | 3,331 | ||||
Property costs | 2,901 | 2,056 | ||||||
Taxes | 893 | 1,016 | ||||||
Other | 108 | 384 | ||||||
Total | $ | 7,821 | $ | 6,787 | ||||
(Thousands of dollars) | Operating Leases | |||
2022 | $ | 601 | ||
2023 | 150 | |||
Total undiscounted lease payments | $ | 751 | ||
Less: Amount associated with discounting | (59 | ) | ||
Net operating lease liabilities | $ | 692 | ||
Year Ended December 31, | ||||||||
(Thousands of dollars) | 2021 | 2020 | ||||||
Asset retirement obligation at beginning of period | $ | 13,660 | $ | 21,118 | ||||
Liabilities incurred | 724 | 4 | ||||||
Liabilities settled | (1,047 | ) | (1,286 | ) | ||||
Liabilities divested | (52 | ) | (5,731 | ) | ||||
Accretion expense | 642 | 856 | ||||||
Revisions in estimated liabilities | 368 | (1,301 | ) | |||||
Asset retirement obligation at end of period | $ | 14,295 | $ | 13,660 | ||||
Year Ended December 31, | ||||||||
(Thousands of dollars) | 2021 | 2020 | ||||||
Current: | ||||||||
Federal | $ | 81 | $ | 950 | ||||
State | 59 | 80 | ||||||
Total current | 140 | 1,030 | ||||||
Deferred: | ||||||||
Federal | 1,802 | (1,491 | ) | |||||
State | 574 | (56 | ) | |||||
Total deferred | 2,376 | (1,547 | ) | |||||
Total income tax provision | $ | 2,516 | $ | (517 | ) | |||
At December 31, | ||||||||
(Thousands of dollars) | 2021 | 2020 | ||||||
Deferred Tax Assets: | ||||||||
Accrued liabilities | $ | 80 | $ | (584 | ) | |||
Allowance for doubtful accounts | 85 | 136 | ||||||
Derivative Contracts | 1,272 | 153 | ||||||
State Net operating loss carry-forwards | 470 | 760 | ||||||
Total deferred tax assets | 1,907 | 465 | ||||||
Deferred Tax Liabilities: | ||||||||
Partnership basis difference | (98 | ) | 544 | |||||
Depletion and depreciation | 40,748 | 36,288 | ||||||
Total deferred tax liabilities | 40,650 | 36,832 | ||||||
Net deferred tax liabilities | $ | 38,743 | $ | 36,367 | ||||
Year Ended December 31, | ||||||||
(Thousands of dollars) | 2021 | 2020 | ||||||
Expected tax expense | $ | 975 | $ | (595 | ) | |||
Net changes in deferred assets and liabilities | 2,376 | (1,547 | ) | |||||
Permanent differences | (677 | ) | 521 | |||||
State income tax, net of federal benefit | 47 | 63 | ||||||
Provision to return adjustment | 744 | 1,547 | ||||||
Tax Credits | (948 | ) | (502 | ) | ||||
Other, net | (1 | ) | (4 | ) | ||||
Total income tax provision (benefit) | $ | 2,516 | $ | (517 | ) | |||
Oil: | ||||
Apache Corporation | 48 | % | ||
Plains All American Inc. | 18 | % | ||
Natural gas and liquids: | ||||
Apache Corporation | 52 | % | ||
Targa Pipeline Mid-Continent West Tex, LLC | 19 | % |
17
December 31, 2021 | Quoted Prices in Active Markets For Identical Assets (Level 1) | Significant Other Observable Inputs (Level 2) | Significant Unobservable Inputs (Level 3) | Balance at December 31, 2021 | ||||||||||||
(Thousands of dollars) | ||||||||||||||||
Assets | ||||||||||||||||
Commodity derivative contracts | $ | — | $ | — | $ | 0 | $ | 0 | ||||||||
Total assets | $ | — | $ | — | $ | 0 | $ | 0 | ||||||||
Liabilities | ||||||||||||||||
Commodity derivative contracts | $ | — | $ | — | $ | (5,585 | ) | $ | (5,585 | ) | ||||||
Total liabilities | $ | — | $ | — | $ | (5,585 | ) | $ | (5,585 | ) | ||||||
December 31, 2020 | Quoted Prices in Active Markets For Identical Assets (Level 1) | Significant Other Observable Inputs (Level 2) | Significant Unobservable Inputs (Level 3) | Balance at December 31, 2020 | ||||||||||||
(Thousands of dollars) | ||||||||||||||||
Assets | ||||||||||||||||
Commodity derivative contracts | $ | — | $ | — | $ | 97 | $ | 97 | ||||||||
Total assets | $ | — | $ | — | $ | 97 | $ | 97 | ||||||||
Liabilities | ||||||||||||||||
Commodity derivative contract | $ | — | $ | — | $ | (768 | ) | $ | (768 | ) | ||||||
Total liabilities | $ | — | $ | — | $ | (768 | ) | $ | (768 | ) | ||||||
(Thousands of dollars) | ||||
Net Liabilities – December 31, 2020 | $ | (671 | ) | |
Total realized and unrealized gains (losses): | ||||
Included in earnings (a) | (9,959 | ) | ||
Purchases, sales, issuances and settlements | 5,045 | |||
Net Liabilities — December 31, 2021 | $ | (5,585 | ) | |
(a) | Derivative instruments are reported in revenues as realized gain/loss and on a separately reported line item captioned unrealized gain/loss on derivative instruments. |
Fair Value | ||||||||||
(Thousands of dollars) | Balance Sheet Location | �� | December 31, 2021 | December 31, 2020 | ||||||
Asset Derivatives: | ||||||||||
Derivatives not designated as cash-flow hedging instruments: | ||||||||||
Natural gas commodity contracts | Derivative asset long-term and | $ | — | $ | 97 | |||||
Total | $ | — | $ | 97 | ||||||
Liability Derivatives: | ||||||||||
Derivatives not designated as cash-flow hedging instruments: | ||||||||||
Crude oil commodity contracts | Derivative liability short-term | $ | (3,992 | ) | $ | (428 | ) | |||
Natural gas commodity contracts | Derivative liability short-term | (943 | ) | (296 | ) | |||||
Crude oil commodity contracts | Derivative liability long-term | (490 | ) | — | ||||||
Natural gas commodity contracts | Derivative liability long-term | (160 | ) | (44 | ) | |||||
Total | $ | (5,585 | ) | $ | (768 | ) | ||||
Total derivative instruments | $ | (5,585 | ) | $ | (671 | ) |
(Thousands of dollars) | Location of gain/loss recognized in income | Amount of gain/loss recognized in income | ||||||||
2021 | 2020 | |||||||||
Derivatives not designated as cash-flow hedge instruments: | ||||||||||
Natural gas commodity contracts | Unrealized (loss) gain on derivative instruments, net | (859 | ) | (351 | ) | |||||
Crude oil commodity contracts | Unrealized (loss) gain on derivative instruments, net | (4,055 | ) | 161 | ||||||
Natural gas commodity contracts | Realized (loss) on derivative instruments, net | (1,833 | ) | 476 | ||||||
Crude oil commodity contracts | Realized (loss) gain on derivative instruments, net | (3,212 | ) | 5,697 | ||||||
$ | (9,959 | ) | $ | 5,983 | ||||||
Year Ended December 31, | ||||||||||||||||||||||||
2021 | 2020 | |||||||||||||||||||||||
Net Income (In 000’s) | Weighted Average Number of Shares Outstanding | Per Share Amount | Net Income (In 000’s) | Weighted Average Number of Shares Outstanding | Per Share Amount | |||||||||||||||||||
Basic | $ | 2,098 | 1,992,077 | $ | 1.05 | $ | (2,316 | ) | 1,994,425 | $ | (1.16 | ) | ||||||||||||
Effect of dilutive securities: | ||||||||||||||||||||||||
Options (a) | — | 752,085 | — | |||||||||||||||||||||
Diluted | $ | 2,098 | 2,744,162 | $ | 0.76 | $ | (2,316 | ) | 1,994,425 | $ | (1.16 | ) | ||||||||||||
(a) | The effect of the 767,000 outstanding stock options is antidilutive for the year ended December 31, 202 0 , due to net loss for this period. |
As of December 31, | ||||||||
(Thousands of dollars) | 2021 | 2020 | ||||||
Proved Developed oil and gas properties | $ | 539,484 | $ | 520,488 | ||||
Proved Undeveloped oil and gas properties | 0 | 0— | ||||||
Total Capitalized Costs | 539,484 | 520,488 | ||||||
Accumulated depreciation, depletion and valuation allowance | (359,742 | ) | (335,390 | ) | ||||
Net Capitalized Costs | $ | 179,742 | $ | 185,098 | ||||
Year Ended December 31, | ||||||||
(Thousands of dollars) | 2021 | 2020 | ||||||
Development Costs | $ | 18,678 | $ | 9,339 |
As of December 31, | ||||||||
(Thousands of dollars) | 2021 | 2020 | ||||||
Future cash inflows | $ | 501,431 | $ | 221,090 | ||||
Future production costs | (207,697 | ) | (100,691 | ) | ||||
Future development costs | (18,507 | ) | (39,167 | ) | ||||
Future income tax expenses | (57,798 | ) | (15,135 | ) | ||||
Future Net Cash Flows | 217,429 | 66,097 | ||||||
10% annual discount for estimated timing of cash flows | (81,623 | ) | (24,479 | ) | ||||
Standardized Measure of Discounted Future Net Cash Flows | $ | 135,806 | $ | 41,619 | ||||
Year Ended December 31, | ||||||||
(Thousands of dollars) | 2021 | 2020 | ||||||
Sales of oil and gas produced, net of production costs | $ | (45,322 | ) | $ | (13,945 | ) | ||
Net changes in prices and production costs | 143,750 | (16,578 | ) | |||||
Extensions, discoveries and improved recovery | 6,440 | 314 | ||||||
Revisions of previous quantity estimates | 18,991 | (36,919 | ) | |||||
Net change in development costs | (12,904 | ) | 20,724 | |||||
Reserves sold | (136 | ) | (874 | ) | ||||
Reserves purchased | 0 | 218 | ||||||
Accretion of discount | 4,162 | 8,161 | ||||||
Net change in income taxes | (21,180 | ) | 5,386 | |||||
Changes in production rates (timing) and other | 386 | (6,480 | ) | |||||
Net change | 94,187 | (39,993 | ) | |||||
Standardized measure of discounted future net cash flow: | ||||||||
Beginning of year | 41,619 | 81,612 | ||||||
End of year | $ | 135,806 | $ | 41,619 | ||||
As of December 31, | ||||||||||||||||||||||||
2021 | 2020 | |||||||||||||||||||||||
Oil (MBbls) | NGL’s (MBbls) | Gas (MMcf) | Oil (MBbls) | NGLs (MBbls) | Gas (MMcf) | |||||||||||||||||||
Proved Developed Reserves: | ||||||||||||||||||||||||
Beginning of year | 2,684 | 2,258 | 13,633 | 4,381 | 2,914 | 19,995 | ||||||||||||||||||
Extensions, discoveries and improved recovery | 69 | 1 | 628 | 11 | 7 | 36 | ||||||||||||||||||
Revisions of previous estimates | 133 | (29 | ) | 5,312 | (995 | ) | (239 | ) | (1,721 | ) | ||||||||||||||
Converted from undeveloped reserves | 1,747 | 231 | 1,067 | 25 | 5 | 66 | ||||||||||||||||||
Reserves sold | 15 | 5 | 26 | (29 | ) | 0 | (1,400 | ) | ||||||||||||||||
Reserve purchased | — | — | — | 24 | 8 | 38 | ||||||||||||||||||
Production | 738 | 416 | 3,236 | (733 | ) | (437 | ) | (3,381 | ) | |||||||||||||||
End of year | 5,386 | 2,882 | 23,902 | 2,684 | 2,258 | 13,633 | ||||||||||||||||||
Proved Undeveloped Reserves: | ||||||||||||||||||||||||
Beginning of year | 1,784 | 787 | 3,897 | 1,833 | 1,017 | 4,547 | ||||||||||||||||||
Extensions, discoveries and improved recovery | (61 | ) | (557 | ) | (2,726 | ) | — | — | — | |||||||||||||||
Revisions of previous estimates | 31 | 4 | 386 | (24 | ) | (224 | (584 | ) | ||||||||||||||||
Converted to developed reserves | (1,747 | ) | (231 | ) | (1,067 | ) | (25 | ) | (5 | ) | (66 | ) | ||||||||||||
Reserves Sold | (7 | ) | (4 | ) | (489 | ) | — | — | — | |||||||||||||||
End of year | — | — | — | 1,784 | 787 | 3,897 | ||||||||||||||||||
Total Proved Reserves at the End of the Year | 5,386 | 2,882 | 23,902 | 4,468 | 3,045 | 17,530 | ||||||||||||||||||
Year Ended December 31, | ||||||||
(Thousands of dollars) | 2021 | 2020 | ||||||
Revenue: | ||||||||
Oil and gas sales | $ | 73,126 | $ | 36,973 | ||||
Costs and Expenses: | ||||||||
Lease operating expenses | 27,804 | 23,028 | ||||||
Depreciation, depletion and accretion | 26,325 | 25,921 | ||||||
Income tax expense | 3,989 | (2,515 | ) | |||||
Total Costs and Expenses | 58,118 | 46,434 | ||||||
Results of Operations from Producing Activities (excluding corporate overhead and interest costs) | $ | 15,008 | $ | (9,461 | ) | |||