UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM10-Q
☒ | QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the Quarterly Period Ended June 30, 20182019
Or
☐ | TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the Transition Period From to
Commission File Number0-7406
PrimeEnergy Resources Corporation
(Exact name of registrant as specified in its charter)
Delaware | 84-0637348 | |
(State or other jurisdiction of incorporation or organization) | (I.R.S. employer Identification No.) |
9821 Katy Freeway, Houston, Texas 77024
(Address of principal executive offices)
(713)735-0000
(Registrant’s telephone number, including area code)
(Former name, former address and former fiscal year, if changed since last report)
Securities registered pursuant to Section 12(b) of the Act
Title of each class | Trading Symbol | Name of each exchange on which registered | ||
Common Stock, par value $0.10 (per share) | PNRG | NASDAQ |
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15 (d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filings required for the past 90 days. Yes ☒ No ☐
Indicate by check mark whether the registrant has submitted electronically, and posted on its corporate web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of RegulationS-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes ☒ No ☐
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, anon-accelerated filer, smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule12b-2 of the Exchange Act.
Large Accelerated Filer | ☐ | Accelerated Filer | ☐ | |||
Non-Accelerated Filer | ☐ | Smaller Reporting Company | ☒ | |||
Emerging growth company | ☐ |
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐
Indicate by check mark whether the registrant is a shell company (as defined in Rule12b-2 of the Exchange Act). Yes ☐ No ☒
The number of shares outstanding of each class of the Registrant’s Common Stock as August 15, 20189, 2019 was: Common Stock, $0.10 par value 2,061,9632,010,613 shares.
PrimeEnergy Resources Corporation
Index to Form10-Q
June 30, 20182019
Item 1. |
PRIMEENERGY RESOURCES CORPORATION
CONDENSEDCONSOLIDATED BALANCE SHEETS –Unaudited
(Thousands of dollars)
June 30, 2018 | December 31, 2017 | June 30, 2019 | December 31, 2018 | |||||||||||||
ASSETS | ||||||||||||||||
Current Assets | ||||||||||||||||
Cash and cash equivalents | $ | 5,441 | $ | 8,438 | $ | 2,821 | $ | 6,315 | ||||||||
Accounts receivable, net | 13,787 | 16,961 | 16,848 | 14,961 | ||||||||||||
Prepaid obligations | 485 | 640 | ||||||||||||||
Derivative asset short-term | 1,081 | 1,674 | ||||||||||||||
Other current assets | 611 | 1,232 | 139 | 144 | ||||||||||||
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Total Current Assets | 19,839 | 26,631 | 21,374 | 23,734 | ||||||||||||
Property and Equipment, at cost | ||||||||||||||||
Oil and gas properties (successful efforts method), net | 215,921 | 213,001 | 216,123 | 223,669 | ||||||||||||
Field and office equipment, net | 6,879 | 6,974 | 6,905 | 6,756 | ||||||||||||
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Total Property and Equipment, Net | 222,800 | 219,975 | 223,028 | 230,425 | ||||||||||||
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Other Assets | 160 | 159 | ||||||||||||||
Derivative asset long-term and other assets. | 623 | 893 | ||||||||||||||
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Total Assets | $ | 242,799 | $ | 246,765 | $ | 245,025 | $ | 255,052 | ||||||||
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LIABILITIES AND EQUITY | ||||||||||||||||
Current Liabilities | ||||||||||||||||
Accounts payable | $ | 12,573 | $ | 24,615 | $ | 13,440 | $ | 9,553 | ||||||||
Accrued liabilities | 9,174 | 16,294 | 6,767 | 18,431 | ||||||||||||
Current portion of long-term debt | 1,289 | 2,378 | — | 698 | ||||||||||||
Current portion of asset retirement | 2,665 | 2,309 | ||||||||||||||
Current portion of asset retirement and other obligations | 2,098 | 1,687 | ||||||||||||||
Derivative liability short-term | 5,716 | 1,509 | 1,675 | 88 | ||||||||||||
Due to Related Parties | 71 | 65 | — | 5 | ||||||||||||
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Total Current Liabilities | 31,488 | 47,170 | 23,980 | 30,462 | ||||||||||||
Long-Term Bank Debt | 59,693 | 48,459 | 62,000 | 65,547 | ||||||||||||
Asset Retirement Obligations | 20,359 | 21,269 | 19,377 | 19,647 | ||||||||||||
Derivative Liability Long-Term | 3,367 | 1,913 | — | 10 | ||||||||||||
Deferred Income Taxes | 25,900 | 24,962 | 33,534 | 32,828 | ||||||||||||
Other Long-Term Obligations | 555 | 553 | 608 | 555 | ||||||||||||
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Total Liabilities | 141,362 | 144,326 | 139,499 | 149,049 | ||||||||||||
Commitments and Contingencies | ||||||||||||||||
Equity | ||||||||||||||||
Common stock, $.10 par value; 2018 and 2017: Authorized: 4,000,000 shares, issued: 3,836,397 shares; outstanding 2018: 2,096,531 shares; 2017: 2,169,370 shares | 383 | 383 | ||||||||||||||
Common stock, $.10 par value; 2019 and 2018: Authorized and Issued: 2,810,000 shares; outstanding 2019: 2,017,508 shares; 2018: 2,039,919 shares | 281 | 281 | ||||||||||||||
Paid-in capital | 8,772 | 8,729 | 7,612 | 7,388 | ||||||||||||
Retained earnings | 141,046 | 138,320 | 128,381 | 125,644 | ||||||||||||
Treasury stock, at cost; 2018: 1,739,866 shares; 2017: 1,667,027 shares | (55,819 | ) | (52,123 | ) | ||||||||||||
Treasury stock, at cost; 2019: 792,492 shares; 2018: 770,081 shares | (34,316 | ) | (31,304 | ) | ||||||||||||
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Total Stockholders’ Equity – PrimeEnergy | 94,382 | 95,309 | 101,958 | 102,009 | ||||||||||||
Non-controlling interest | 7,055 | 7,130 | 3,568 | 3,994 | ||||||||||||
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Total Equity | 101,437 | 102,439 | 105,526 | 106,003 | ||||||||||||
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Total Liabilities and Equity | $ | 242,799 | $ | 246,765 | $ | 245,025 | $ | 255,052 | ||||||||
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PRIMEENERGY RESOURCES CORPORATION
CONDENSED CONSOLIDATED STATEMENTSOF OPERATIONS– Unaudited
Three and six months ended June 30, 20182019 and 20172018
(Thousands of dollars, except per share amounts)
Three Months Ended June 30, | Six Months Ended June 30, | Three Months Ended June 30, | Six Months Ended June 30, | |||||||||||||||||||||||||||||
2018 | 2017 | 2018 | 2017 | 2019 | 2018 | 2019 | 2018 | |||||||||||||||||||||||||
Revenues | ||||||||||||||||||||||||||||||||
Oil and gas sales | $ | 16,622 | $ | 10,237 | $ | 36,723 | $ | 18,911 | ||||||||||||||||||||||||
Oil sales | $ | 19,644 | $ | 16,622 | $ | 38,442 | $ | 36,723 | ||||||||||||||||||||||||
Natural gas sales | 1,989 | 2,505 | 4,352 | 5,163 | 1,355 | 1,989 | 3,590 | 4,352 | ||||||||||||||||||||||||
Natural gas liquids sales | 3,098 | 1,261 | 5,698 | 2,367 | 2,375 | 3,098 | 5,219 | 5,698 | ||||||||||||||||||||||||
Realized (loss) gain on derivative instruments, net | (1,081 | ) | 22 | (1,576 | ) | (205 | ) | |||||||||||||||||||||||||
Realized loss on derivative instruments, net | (851 | ) | (1,081 | ) | (773 | ) | (1,576 | ) | ||||||||||||||||||||||||
Field service income | 4,447 | 4,306 | 8,662 | 8,067 | 4,757 | 4,447 | 9,490 | 8,662 | ||||||||||||||||||||||||
Administrative overhead fees | 1,426 | 1,647 | 2,930 | 3,228 | 1,388 | 1,426 | 2,812 | 2,930 | ||||||||||||||||||||||||
Unrealized (loss) gain on derivative instruments, net | (4,136 | ) | 1,550 | (5,957 | ) | 4,354 | ||||||||||||||||||||||||||
Unrealized gain (loss) on derivative instruments, net | 2,862 | (4,136 | ) | (2,890 | ) | (5,957 | ) | |||||||||||||||||||||||||
Other income | 22 | 4 | 22 | 122 | 4 | 22 | 63 | 22 | ||||||||||||||||||||||||
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Total Revenues | 22,387 | 21,532 | 50,854 | 42,007 | 31,534 | 22,387 | 55,953 | 50,854 | ||||||||||||||||||||||||
Costs and Expenses | ||||||||||||||||||||||||||||||||
Lease operating expense | 8,757 | 7,157 | 17,336 | 14,296 | 8,149 | 8,757 | 16,225 | 17,336 | ||||||||||||||||||||||||
Field service expense | 3,219 | 3,044 | 6,429 | 6,026 | 3,979 | 3,219 | 7,644 | 6,429 | ||||||||||||||||||||||||
Depreciation, depletion, amortization and accretion on discounted | 7,909 | 8,071 | 15,832 | 16,009 | 9,292 | 7,909 | 18,550 | 15,832 | ||||||||||||||||||||||||
General and administrative expense | 2,571 | 2,620 | 8,547 | 4,355 | 2,895 | 2,571 | 9,771 | 8,547 | ||||||||||||||||||||||||
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Total Costs and Expenses | 22,456 | 20,892 | 48,144 | 40,686 | 24,315 | 22,456 | 52,190 | 48,144 | ||||||||||||||||||||||||
Gain on Sale and Exchange of Assets | 185 | 117 | 2,657 | 41,719 | 1,023 | 185 | 1,689 | 2,657 | ||||||||||||||||||||||||
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Income from Operations | 116 | 757 | 5,369 | 43,040 | 8,242 | 116 | 5,452 | 5,367 | ||||||||||||||||||||||||
Other Income (Expense) | ||||||||||||||||||||||||||||||||
Interest Income | 12 | — | 23 | — | 3 | 12 | 10 | 23 | ||||||||||||||||||||||||
Interest (Expense) | (917 | ) | (460 | ) | (1,779 | ) | (1,065 | ) | (1,013 | ) | (917 | ) | (1,988 | ) | (1,779 | ) | ||||||||||||||||
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Income (Loss) Before Income Taxes | (789 | ) | 297 | 3,611 | 41,975 | 7,232 | (789 | ) | 3,474 | 3,611 | ||||||||||||||||||||||
Income Taxes (Benefit) Expense | (192 | ) | 124 | 907 | 13,791 | |||||||||||||||||||||||||||
Income Taxes Expense (Benefit) | 1,410 | (192 | ) | 683 | 907 | |||||||||||||||||||||||||||
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Net (Loss) Income | (597 | ) | 173 | 2,704 | 28,184 | |||||||||||||||||||||||||||
Less: Net (Loss) Income Attributable toNon-Controlling Interests | (37 | ) | (188 | ) | (22 | ) | 5,525 | |||||||||||||||||||||||||
Net Income (Loss) | 5,822 | (597 | ) | 2,791 | 2,704 | |||||||||||||||||||||||||||
Less: Net Income (Loss) Attributable toNon-Controlling Interests | 47 | (37 | ) | 54 | (22 | ) | ||||||||||||||||||||||||||
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Net (Loss) Income Attributable to PrimeEnergy | $ | (560 | ) | $ | 361 | 2,726 | $ | 22,659 | ||||||||||||||||||||||||
Net Income (Loss) Attributable to PrimeEnergy | $ | 5,775 | $ | (560 | ) | 2,737 | 2,726 | |||||||||||||||||||||||||
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Basic (Loss) Income Per Common Share | $ | (0.27 | ) | $ | 0.16 | $ | 1.29 | $ | 10.11 | |||||||||||||||||||||||
Basic Income (Loss) Per Common Share | $ | 2.85 | $ | (0.27 | ) | $ | 1.35 | $ | 1.29 | |||||||||||||||||||||||
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Diluted (Loss) Income Per Common Share | $ | (0.27 | ) | $ | 0.12 | $ | 0.95 | $ | 7.57 | |||||||||||||||||||||||
Diluted Income (Loss) Per Common Share | $ | 2.07 | $ | (0.27 | ) | $ | 0.98 | $ | 0.95 | |||||||||||||||||||||||
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PRIMEENERGY RESOURCES CORPORATION
CONDENSED CONSOLIDATED STATEMENTOF EQUITY –Unaudited
Six months ended June 30, 20182019 and 20172018
(Thousands of dollars)
Common Stock | Additional Paid in | Retained | Treasury | Total Stockholders’ Equity – | Non-Controlling | Total | Common Stock | Additional Paid in | Retained | Treasury | Total Stockholders’ Equity – | Non-Controlling | Total | |||||||||||||||||||||||||||||||||||||||||||||||||||
Shares | Amount | Capital | Earnings | Stock | PrimeEnergy | Interest | Equity | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Balance at December 31, 2016 | 3,836,397 | $ | 383 | $ | 8,313 | $ | 96,322 | $ | (46,473 | ) | $ | 58,545 | $ | 7,335 | $ | 65,880 | ||||||||||||||||||||||||||||||||||||||||||||||||
Repurchase 92,824 shares of common stock | — | — | — | — | (4,605 | ) | (4,605 | ) | — | (4,605 | ) | |||||||||||||||||||||||||||||||||||||||||||||||||||||
Net income | — | — | — | 22,659 | — | 22,659 | 5,525 | 28,184 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Repurchase ofNon-controlling interests | — | — | 126 | — | — | 126 | (187 | ) | (61 | ) | ||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Balance at June 30, 2017 | 3,836,397 | $ | 383 | $ | 8,439 | $ | 118,981 | $ | (51,078 | ) | $ | 76,725 | $ | 12,673 | $ | 89,398 | ||||||||||||||||||||||||||||||||||||||||||||||||
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| Shares | Amount | Capital | Earnings | Stock | PrimeEnergy | Interest | Equity | |||||||||||||||||||||||||||||||||||||||||||||||||
Balance at December 31, 2017 | 3,836,397 | $ | 383 | $ | 8,729 | $ | 138,320 | $ | (52,123 | ) | $ | 95,309 | $ | 7,130 | $ | 102,439 | 3,836,397 | $ | 383 | $ | 8,729 | $ | 138,320 | $ | (52,123 | ) | $ | 95,309 | $ | 7,130 | $ | 102,439 | ||||||||||||||||||||||||||||||||
Repurchase 72,839 shares of common stock | — | — | — | — | (3,696 | ) | (3,696 | ) | — | (3,696 | ) | — | — | — | — | (3,696 | ) | (3,696 | ) | — | (3,696 | ) | ||||||||||||||||||||||||||||||||||||||||||
Net income (loss) | — | — | — | 2,726 | — | 2,726 | (22 | ) | 2,704 | — | — | — | 2,726 | — | 2,726 | (22 | ) | 2,704 | ||||||||||||||||||||||||||||||||||||||||||||||
Purchase ofNon- controlling Interest | — | — | 43 | — | — | 43 | (53 | ) | (10 | ) | — | — | 43 | — | — | 43 | (53 | ) | (10 | ) | ||||||||||||||||||||||||||||||||||||||||||||
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Balance at June 30, 2018 | 3,836,397 | $ | 383 | $ | 8,772 | $ | 141,046 | $ | (55,819 | ) | $ | 94,382 | $ | 7,055 | $ | 101,437 | 3,836,397 | $ | 383 | $ | 8,772 | $ | 141,046 | $ | (55,819 | ) | $ | 94,382 | $ | 7,055 | $ | 101,437 | ||||||||||||||||||||||||||||||||
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Balance at December 31, 2018 | 2,810,000 | $ | 281 | $ | 7,388 | $ | 125,644 | $ | (31,304 | ) | $ | 102,009 | $ | 3,994 | $ | 106,003 | ||||||||||||||||||||||||||||||||||||||||||||||||
Repurchase 22,411 shares of common stock | — | — | — | — | (3,012 | ) | (3,012 | ) | — | (3,012 | ) | |||||||||||||||||||||||||||||||||||||||||||||||||||||
Net income | — | — | — | 2,737 | — | 2,737 | 54 | 2,791 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Purchase ofNon- controlling Interest | — | — | 224 | — | — | 224 | (480 | ) | (256 | ) | ||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Balance at June 30, 2019 | 2,810,000 | $ | 281 | $ | 7,612 | $ | 128,381 | $ | (34,316 | ) | $ | 101,958 | $ | 3,568 | $ | 105,526 | ||||||||||||||||||||||||||||||||||||||||||||||||
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PRIMEENERGY RESOURCES CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS –Unaudited
Six months ended June 30, 20182019 and 20172018
(Thousands of dollars)
2018 | 2017 | 2019 | 2018 | |||||||||||||
Cash Flows from Operating Activities: | ||||||||||||||||
Net Income includingnon-controlling interest | $ | 2,704 | $ | 28,184 | $ | 2,791 | $ | 2,704 | ||||||||
Adjustments to reconcile net income to net cash provided by operating activities: | ||||||||||||||||
Depreciation, depletion, amortization and accretion on discounted liabilities | 15,832 | 16,009 | 18,550 | 15,832 | ||||||||||||
Gain on sale of properties | (2,657 | ) | (41,719 | ) | (1,689 | ) | (2,657 | ) | ||||||||
Unrealized loss (gain) on derivative instruments, net | 5,957 | (4,354 | ) | |||||||||||||
Unrealized loss on derivative instruments, net | 2,890 | 5,957 | ||||||||||||||
Provision for deferred income taxes | 938 | 7,305 | 706 | 961 | ||||||||||||
Changes in operating assets and liabilities: | ||||||||||||||||
Accounts receivable | 3,174 | (2,252 | ) | (1,887 | ) | 3,174 | ||||||||||
Due to related parties | 6 | 352 | (5 | ) | 6 | |||||||||||
Other assets | 620 | (1,105 | ) | 160 | 620 | |||||||||||
Accounts payable | (12,042 | ) | (2,647 | ) | 3,887 | (12,042 | ) | |||||||||
Accrued liabilities | (7,121 | ) | 14,760 | (11,664 | ) | (7,121 | ) | |||||||||
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Net Cash Provided by Operating Activities | 7,434 | 14,533 | 13,739 | 7,434 | ||||||||||||
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Cash Flows from Investing Activities: | ||||||||||||||||
Capital expenditures | (18,788 | ) | (30,463 | ) | (11,412 | ) | (18,709 | ) | ||||||||
Proceeds from sale of properties and equipment | 2,112 | 46,572 | 1,693 | 2,112 | ||||||||||||
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Net Cash (Used in) Provided by Investing Activities | (16,597 | ) | 16,109 | |||||||||||||
Net Cash Used in Investing Activities | (9,719 | ) | (16,597 | ) | ||||||||||||
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Cash Flows from Financing Activities: | ||||||||||||||||
Purchase of stock for treasury | (3,696 | ) | (4,605 | ) | (3,012 | ) | (3,696 | ) | ||||||||
Purchase ofnon-controlling interests | (10 | ) | (60 | ) | (256 | ) | (10 | ) | ||||||||
Proceeds from long-term bank debt and other long-term obligations | 35,300 | 42,000 | 13,000 | 35,300 | ||||||||||||
Repayment of long-term bank debt and other long-term obligations | (25,428 | ) | (66,823 | ) | (17,246 | ) | (25,428 | ) | ||||||||
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Net Cash Provided by (Used in) Financing Activities | 6,166 | (29,488 | ) | |||||||||||||
Net Cash (Used in) Provided by Financing Activities | (7,514 | ) | 6,166 | |||||||||||||
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Net (Decrease) Increase in Cash and Cash Equivalents | (2,997 | ) | 1,154 | (3,494 | ) | (2,997 | ) | |||||||||
Cash and Cash Equivalents at the Beginning of the Period | 8,438 | 6,588 | 6,315 | 8,438 | ||||||||||||
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Cash and Cash Equivalents at the End of the Period | $ | 5,441 | $ | 7,222 | $ | 2,821 | $ | 5,441 | ||||||||
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Supplemental Disclosures: | ||||||||||||||||
Income taxes paid | $ | 4,341 | $ | 2,587 | $ | 130 | $ | 4,341 | ||||||||
Interest paid | $ | 1,950 | $ | 1,356 | $ | 2,015 | $ | 1,950 |
The accompanying Notes are an integral part of these Condensed Consolidated Financial Statements
PRIMEENERGY RESOURCES CORPORATION
NOTESTO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
June 30, 20182019
(Unaudited)
(1) Basis of Presentation:
The accompanying condensed consolidated financial statements of PrimeEnergy Resources Corporation (“PrimeEnergy” or the “Company”) have not been audited by independent public accountants. Pursuant to applicable Securities and Exchange Commission (“SEC”) rules and regulations, the accompanying interim financial statements do not include all disclosures presented in annual financial statements and the reader should refer to the Company’s Form10-K for the year ended December 31, 2017.2018. In the opinion of management, the accompanying interim condensed consolidated financial statements contain all material adjustments, consisting only of normal recurring adjustments, necessary for a fair presentation of the Company’s condensed consolidated balance sheets as of June 30, 20182019 and December 31, 2017,2018, the condensed consolidated results of operations, cash flows and equity for the six months ended June 30, 20182019 and 2017.2018.
As of June 30, 2018,2019, PrimeEnergy’s significant accounting policies are consistent with those discussed in Note 1—Description of Operations and Significant Accounting Policies of its consolidated financial statements contained in PrimeEnergy’s Annual Report on Form10-K for the fiscal year ended December 31, 2017,2018, with the exception of Accounting Standards Update (ASU)2014-09,2016-02, “Revenue from Contracts with Customers“Leases (Topic 606)842)” discussed below. Certain amounts presented in prior period financial statements have been reclassified for consistency with current period presentation. The results for interim periods are not necessarily indicative of annual results. For purposes of disclosure in the condensed consolidated financial statements, subsequent events have been evaluated through the date the statements were issued.
Recently Adopted Accounting Pronouncements
On January 1, 2018, PrimeEnergy adopted ASU2014-09, “Revenue from Contracts with Customers (ASC 606),” using the modified retrospective method. The Company elected to evaluate all contracts at the date of initial application. While there was no impact to the opening balance of retained earnings as a result of the adoption, certain items previously netted in revenue are now recognized as lease operating expense in the Company’s statement of consolidated operations. The amounts are immaterial to the financial statements, and prior comparative periods have not been restated and continue to be reported under the accounting standards in effect for those periods. Adoption of the new standard is not anticipated to have a material impact on the Company’s net earnings on an ongoing basis.
The Company applies the provisions of ASC 606 for revenue recognition to contracts with customers. Sales of crude oil, natural gas, and natural gas liquids (NGLs) are included in revenue when production is sold to a customer in fulfillment of performance obligations under the terms of agreed contracts. Performance obligations primarily comprise delivery of oil, gas, or NGLs at a delivery point, as negotiated within each contract. Each barrel of oil, million Btu (MMBtu) of natural gas, or other unit of measure is separately identifiable and represents a distinct performance obligation to which the transaction price is allocated. Performance obligations are satisfied at a point in time once control of the product has been transferred to the customer. The Company considers a variety of facts and circumstances in assessing the point of control transfer, including but not limited to: whether the purchaser can direct the use of the hydrocarbons, the transfer of significant risks and rewards, the Company’s right to payment, and transfer of legal title. In each case, the term between delivery and when payments are due is not significant.
PrimeEnergy records trade accounts receivable for its unconditional rights to consideration arising under sales contracts with customers. The carrying value of such receivables, net of the allowance for doubtful accounts, represents estimated net realizable value. The Company routinely assesses the collectability of all material trade and other receivables. The Company accrues a reserve on a receivable when, based on the judgment of management, it is probable that a receivable will not be collected and the amount of any reserve may be reasonably estimated. PrimeEnergy has concluded that the disaggregation of revenue by product appropriately depicts how the nature, amount, timing, and uncertainty of revenue and cash flows are affected by economic factors.
Practical Expedients and Exemptions
PrimeEnergy does not disclose the value of unsatisfied performance obligations for contracts with an original expected length of one year or less or contracts for which variable consideration is allocated entirely to a wholly unsatisfied performance obligation.
PrimeEnergy will utilize the practical expedient to expense incremental costs of obtaining a contract if the expected amortization period is one year or less. Costs to obtain a contract with expected amortization periods of greater than one year will be recorded as an asset and will be recognized in accordance with ASC 340, “Other Assets and Deferred Costs.” Currently, the Company does not have contract assets related to incremental costs to obtain a contract.
New Pronouncements Issued But Not Yet Adopted
Leases.In February 2016, the Financial Accounting Standards Board (FASB)(“FASB”) issued ASUAccounting Standards Update (“ASU”)2016-02, “Leases (Topic 842),” requiring(“ASC 842”) which supersedes the lease recognition requirements in Accounting Standards Codification (“ASC”) 840, “Leases” (“ASC 840”), and requires lessees to recognize lease assets and lease liabilities for mostthose leases previously classified as operating leases. The Company adopted ASC 842 as of January 1, 2019 using the modified retrospective transition method. The Company elected to apply the transition guidance under ASU2018-11, “Leases (Topic 842) Targeted Improvements,” in which ASC 842 is applied at the adoption date, while the comparative periods continue to be reported in accordance with historic accounting under ASC 840. This standard does not apply to leases under previous GAAP. to explore for or use minerals, oil or gas resources, including the right to explore for those natural resources and rights to use the land in which those natural resources are contained.
ASC 842 allowed for the election of certain practical expedients at adoption to ease the burden of implementation. At implementation, the Company elected to (i) maintain the historical lease classification for leases prior to January 1, 2019, (ii) maintain the historical accounting treatment for land easements that existed at adoption, (iii) use historical practices in assessing the lease term of existing contracts at adoption, (iv) combine lease andnon-lease components of a contract as a single lease and (v) not record short-term leases on the consolidated balance sheet, all in accordance with ASC 842.
The guidanceadoption of ASC 842 did not have a material impact on the consolidated statements of operations and had no impact on cash flows. The Company did not record a change to its opening retained earnings as of January 1, 2019, as there was no material change to the timing or pattern of recognition of lease costs due to the adoption of ASC 842. As of June 30, 2019, the Company has operating lease assets and liabilities of $452 thousand and a financing lease included in property and equipment and lease liabilities for $13 thousand.
New Pronouncements Issued But Not Yet Adopted
In August 2018, the FASB issued ASU2018-13, “Disclosure Framework: Changes to the Disclosure Requirements for Fair Value Measurement,” which changes the disclosure requirements for fair value measurements by removing, adding, and modifying certain disclosures. ASU2018-13 is effective for financial statements issued for annual periods beginning after December 15, 2019, and interim periods within those annual periods. Early adoption is permitted. The company is currently evaluating the impact of adoption of this ASU on its related disclosures and does not expect it to have a material impact on its financial statements.
In August 2018, the FASB issued ASU2018-15, “Customer’s Accounting for Implementation Costs Incurred in a Cloud Computing Arrangement That is a Service Contract.” This pronouncement clarifies the requirements for capitalizing implementation costs in cloud computing arrangements and aligns them with the requirements for capitalizing implementation costs incurred to develop or obtaininternal-use software. This pronouncement is effective for fiscal years, and for interim periods within those fiscal
years, beginning after December 15, 2018.2019. Early adoption is permitted; however,permitted, including adoption in any interim period for which financial statements have not been issued. The Company is currently evaluating the Company does not intend to early adopt. In January 2018, the FASB issued a proposedimpact of adoption of this ASU update that would add a transition option permitting entities to apply the provisions of the new standard at its adoption date instead of the earliest comparative period presented in the consolidated financial statements. If finalized, comparative reporting would not be required and the provisions of the standard would be applied prospectively to leases in effect at the date of adoption. In the normal course of business, the Company enters into various lease agreements for office space and equipment related to its exploration and development activities that are currently accounted for as operating leases. At this time, the Company cannot reasonably estimate the financial impact this will have on its consolidated financial statements; however, the Company believes adoptionstatements and implementation of this ASU willdoes not significantly impact its balance sheet.expect it to have a material impact.
(2)(2) Acquisitions and Dispositions:
Historically the Company has repurchased the interests of the partners and trust unit holders in the oil and gas limited partnerships (the “Partnerships”) and the asset and business income trusts (the “Trusts”) managed by the Company as general partner and as managing trustee, respectively. The Company purchased such interests in amounts totaling $10,000$256,000 and $60,000$10,000 for the six months ended June 30, 20182019 and 2017,2018, respectively.
During the first six months ended June 30,of 2019 and 2018, the Company sold or farmed out interests in certainnon-core undeveloped oil and natural gas properties and undeveloped acreage through a number of separate, individually negotiated transactions in exchange for cash or cash and a royalty or working interest in Texas, Oklahoma, Kansas, Colorado and Texas.West Virginia. Proceeds under these agreements were $1.6 million and $2.8 million. million, respectively.
During this same time periodthe first six months of 2018, the Company acquired approximately 464 net mineral acres and working interest in 53 oil and gas wells ranging from 16.6% to 33.4%, plus one commercial salt water disposal well, for $6,080,000. This acreage$6.08 million and group of wells are all operated by the Companysold or farmed out interests in certainnon-core undeveloped oil and natural gas properties located in Reagan County,Oklahoma, Kansas, Colorado and Texas, where future horizontal drilling will likely occur.
3)(3) Additional Balance Sheet Information:
Certain balance sheet amounts are comprised of the following:
(Thousands of dollars) | June 30, 2018 | December 31, 2017 | June 30, 2019 | December 31, 2018 | ||||||||||||
Accounts Receivable: | ||||||||||||||||
Joint interest billing | $ | 2,949 | $ | 3,173 | $ | 2,303 | $ | 1,976 | ||||||||
Trade receivables | 1,957 | 941 | 2,725 | 1,979 | ||||||||||||
Oil and gas sales | 8,618 | 12,941 | 11,131 | 6,112 | ||||||||||||
Tax refund receivable | — | 4,760 | ||||||||||||||
Other | 361 | 4 | 913 | 358 | ||||||||||||
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13,885 | 17,059 | 17,072 | 15,185 | |||||||||||||
Less: Allowance for doubtful accounts | (98 | ) | (98 | ) | (224 | ) | (224 | ) | ||||||||
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Total | $ | 13,787 | $ | 16,961 | $ | 16,848 | $ | 14,961 | ||||||||
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Accounts Payable: | ||||||||||||||||
Accounts Payable: | ||||||||||||||||
Trade | $ | 3,014 | $ | 14,317 | $ | 5,399 | $ | 1,174 | ||||||||
Royalty and other owners | 6,441 | 7,073 | 5,742 | 6,197 | ||||||||||||
Partner advances | 1,161 | 1,268 | 1,335 | 1,357 | ||||||||||||
Prepaid drilling deposits | 103 | 67 | ||||||||||||||
Other | 1,854 | 1,890 | 964 | 825 | ||||||||||||
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Total | $ | 12,573 | $ | 24,615 | $ | 13,440 | $ | 9,553 | ||||||||
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Accrued Liabilities: | ||||||||||||||||
Accrued Liabilities: | ||||||||||||||||
Compensation and related expenses | $ | 2,165 | $ | 2,449 | $ | 3,161 | $ | 2,907 | ||||||||
Property costs | 6,605 | 9,141 | 3,606 | 14,993 | ||||||||||||
Income Tax | — | 4,180 | ||||||||||||||
Other | 404 | 524 | — | 531 | ||||||||||||
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Total | $ | 9,174 | $ | 16,294 | $ | 6,767 | $ | 18,431 | ||||||||
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(4) Property and Equipment:
Property and equipment at June 30, 20182019 and December 31, 20172018 consisted of the following:
(Thousands of dollars) | June 30, 2018 | December 31, 2017 | June 30, 2019 | December 31, 2018 | ||||||||||||
Proved oil and gas properties, at cost | $ | 490,522 | $ | 476,570 | $ | 522,239 | $ | 514,821 | ||||||||
Less: Accumulated depletion and depreciation | (274,601 | ) | (263,569 | ) | (306,116 | ) | (291,152 | ) | ||||||||
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Oil and Gas Properties, Net | $ | 215,921 | $ | 213,001 | $ | 216,123 | $ | 223,669 | ||||||||
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Field and office equipment | $ | 26,690 | $ | 26,241 | $ | 28,188 | $ | 27,252 | ||||||||
Less: Accumulated depreciation | (19,811 | ) | (19,267 | ) | (21,283 | ) | (20,496 | ) | ||||||||
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Field and Office Equipment, Net | $ | 6,879 | $ | 6,974 | $ | 6,905 | $ | 6,756 | ||||||||
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Total Property and Equipment, Net | $ | 222,800 | $ | 219,975 | $ | 223,028 | $ | 230,425 | ||||||||
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(5) Long-Term Debt:
Bank Debt:
On February 15, 2017, the Company and its lenders entered into a Third Amended and Restated Credit Agreement (the “2017 Credit Agreement”) with a maturity date of February 15, 2021. The Second Amended and Restated Credit Agreement and subsequent amendments were amended and restated by the 2017 Credit Agreement. Pursuant to the terms and conditions of the 2017 Credit Agreement, the Company has a revolving line of credit and letter of credit facility of up to $300 million subject to a borrowing base that is determined semi-annually by the lenders based upon the Company’s financial statements and the estimated value of the Company’s oil and gas properties, in accordance with the Lenders’ customary practices for oil and gas loans. The credit facility is secured by substantially all of the Company’s oil and gas properties. The 2017 Credit Agreement includes terms and covenants that require the Company to maintain a minimum current ratio, total indebtedness to EBITDAX (earnings before depreciation, depletion, amortization, taxes, interest expense and exploration costs) ratio and interest coverage ratio, as defined, and restrictions are placed on the payment of dividends, the amount of treasury stock the Company may purchase, commodity hedge agreements, and loans and investments in its consolidated subsidiaries and limited partnerships.
On December 22, 2017, the Company and its lenders entered into a First Amendment to the Third Amended and Restated Credit Agreement. The credit agreement includes the addition of a new lender and retains all other aspects of the original credit agreement. As of the effective date of this amendment the Company’s borrowing base was increased to $85 million.
On July 17, 2018, the Company and its lenders entered into a Second Amendment to the Third Amended and Restated Credit Agreement. The credit agreement includes modifications for the borrowing base utilization margins and rates by type of borrowing, revises minimum quantifications for individual borrowings, reduces the overall percentage required for commodity hedge agreements, modifies the requirements placed on the company’scompanies’ ability to purchase equity interests and retains all other aspects of the original credit agreement. As of the effective date of this amendment the Company’s borrowing base was increased to $90 million.
On January 8, 2019, the Company and its lenders entered into a Third Amendment to the Third Amended and Restated Credit Agreement. The credit agreement includes additions for a Beneficial Ownership Certification on the effective date of the amendment. The agreement includes further clarifications for potential Libor loan market rate issues, swap agreement modifications and retains all other aspects of the original credit agreement. As of the effective date of this amendment the Company’s borrowing base was increased to $100 million. Effective on June 26, 2019 the Company’s lenders adjusted the borrowing base to $90 million.
At June 30 2018,2019, the Company had a total of $59.5$62 million of borrowings outstanding under its revolving credit facility at a weighted-average interest rate of 5.59%5.52% and $25.5$28 million available for future borrowings. The combined weighted average interest rate paid on outstanding bank borrowings subject to base rate and LIBO interest was 5.38%5.53% for the six months ended June 30, 20182019 as compared to 5.20%5.38% for six months ended June 30, 2017.2018. The Company’s borrowings under this credit facility approximates fair value because the interest rates are variable and reflective of market rates.
Equipment Loans:
On July 31, 2013, the Company entered into a $10.0 million Loan and Security Agreement with JP Morgan Chase Bank (“Equipment Loan”). The Equipment Loan is secured by a portion of the Company’s field service equipment, carries an interest rate of 3.95% per annum, requires monthly payments (principal and interest) of $184,000, and has a final maturity date of July 31, 2018. As of June 30, 2018 the Company had a total of $179 thousand outstanding on this Equipment Loan.
On July 29, 2014, the Company entered into additional equipment financing facilities (“Additional Equipment Loans”) totaling $6.0 million with JP Morgan Chase Bank. In August 2014, the Company drew down $4.8 million of this facility that is secured by field service equipment, carries an interest rate of 3.40% per annum, requires monthly payments (principal and interest) of $87,800, and has a final maturity date of July 31, 2019. The remaining $1.2 million under the Additional Equipment Loans was available for interim draws to finance the acquisition of any future field service equipment. In December 2014, the Company made an interim draw
of an additional $0.5 million on this facility.facility that is secured by recently purchased field service equipment. Interim draws on this facility carried a floating interest rate; payable monthly at the LIBO published rate plus 2.50% and on June 26, 2015 converted into a fixed term loan, with a rate of 3.50% and requiring monthly payments (principal and interest) of $8,700 with a final maturity date of June 26, 2020. As of June 30, 2018, the Company had a total of $1.302 million outstanding on the Additional Equipment Loans.
On January 12, 2018, the Company made a principal payment towards the third interim loan in the amount of $20,858. Effective with the payment due of January 26, 2018 the required monthly payments (principal and interest) on this loan changed to $7,986 with a continuing effective rate of 3.50% and a final maturity of June 26, 2020.
TheOn May 23, 2019, the Company determinedmade its final payment towards both the second and third loans. At this time all equipment loans have been paid in full and the field service equipment liens secured by these loans are Level 3 liabilities inhave been cancelled and all titles returned to the fair-value hierarchy and estimated their fair value as $1.346 million and $4.751 million at June 30, 2018 and 2017, respectively, using a discounted cash flow model.Company.
(6) Other Long-Term Obligations and Commitments:
Operating Leases:
The Company has severalnon-cancelableleases office facilities under operating leases primarilyand recognizes lease expense on a straight-line basis over the lease term. Leases assets and liabilities are initially recorded at commencement date based on the present value of lease payments over the lease term. A new finance lease for rentaloffice equipment is included in property and equipment, other current liabilities and other long-term liabilities this quarter. As most of office space,the Company’s lease contracts do not provide an implicit discount rate, the Company uses its incremental borrowing rate based on the information available at commencement date in determining the present value of lease payments. The weighted average discount rate used was 5.5%. Certain leases may contain variable costs above the minimum required payments and are not included in theright-of-use assets or liabilities. Leases may include renewal, purchase or termination options that have acan extend or shorten the term of more than one year.the lease. The future minimumexercise of those options is at the Company’s sole discretion and is evaluated at inception and throughout the contract to determine if a modification of the lease payments forterm is required. Leases with an initial term of 12 months or less are not recorded on the rest of fiscal 2018 and thereafter for the operating leases are as follows:balance sheet.
(Thousands of dollars) | Operating Leases | |||
2018 | $ | 267 | ||
2019 | 236 | |||
2020 | 69 | |||
2021 | 17 | |||
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Total minimum payments | $ | 589 | ||
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Rent expense for office spaceOperating lease costs for the six months ended June 30, 20182019 were $293 thousand. Cash payments included in the operating lease cost for the six months ended June 30, 2019 were $284 thousand. The weighted-average remaining operating lease terms is 12 months. The amortization and 2017interest expense for financing lease amounted to $1,275 and the cash payment for the lease was $296,000$1,200 and $340,000, respectively.
(Thousands of dollars) | Operating Leases | Financing Leases | ||||||
2019 | $ | 299 | $ | 5 | ||||
2020 | 155 | 7 | ||||||
2021 | 17 | 2 | ||||||
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Total undiscounted lease payments | $ | 471 | $ | 14 | ||||
Less: Amount associated with discounting | (19 | ) | (1 | ) | ||||
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Net operating lease liabilities | $ | 452 | $ | 13 | ||||
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Asset Retirement Obligation:
A reconciliation of the liability for plugging and abandonment costs for the six months ended June 30, 20182019 is as follows:
(Thousands of dollars) | June 30, 2019 | |||||||
Asset retirement obligation – December 31, 2017 | $ | 23,578 | ||||||
Asset retirement obligation at December 31, 2018 | $ | 21,334 | ||||||
Liabilities incurred | — | — | ||||||
Liabilities settled | (1,114 | ) | (829 | ) | ||||
Accretion expense | 560 | 560 | ||||||
Revisions in estimated liabilities | — | |||||||
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Asset retirement obligation – June 30, 2018 | $ | 23,024 | ||||||
Asset retirement obligation at June 30, 2019 | $ | 21,065 | ||||||
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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.
(7) Contingent Liabilities:
The Company, as managing general partner of the affiliated Partnerships, is responsible for all Partnership activities, including the drilling of development wells and the production and sale of oil and gas from productive wells. The Company also provides the administration, accounting and tax preparation work for the Partnerships, and is liable for all debts and liabilities of the affiliated Partnerships, to the extent that the assets of a given limited Partnership are not sufficient to satisfy its obligations.
The Company is subject to environmental laws and regulations. Management believes that future expenses, before recoveries from third parties, if any, will not have a material effect on the Company’s financial condition. This opinion is based on expenses incurred to date for remediation and compliance with laws and regulations, which have not been material to the Company’s results of operations.
From time to time, the Company is party to certain legal actions arising in the ordinary course of business. While the outcome of these events cannot be predicted with certainty, management does not expect these matters to have a materially adverse effect on the financial position or results of operations of the Company.
(8) Stock Options and Other Compensation:
In May 1989,non-statutory stock options were granted by the Company to four key executive officers for the purchase of shares of common stock. At June 30, 20182019 and 2017,December 31, 2018, remaining options held by two key executive officers on 767,500 shares were outstanding and exercisable at prices ranging from $1.00 to $1.25. According to their terms, the options have no expiration date.
(9) Related Party Transactions:
The Company, as managing general partner or managing trustee, makes an annual offer to repurchase the interests of the partners and trust unit holders in certain of the Partnerships andor Trusts. The Company purchased interests totaling $10,000$256,000 and $60,000$10,000 for the six months ended June 30, 2019 and 2018, and 2017, respectively.
Payables owed to related parties primarily represent receipts collected by the Company as agent for the joint venture partners, which may include members of the Company’s Board of Directors, for oil and gas sales net of expenses.
(10) Financial Instruments
Fair Value Measurements:
Authoritative guidance on fair value measurements defines fair value, establishes a framework for measuring fair value and stipulates the related disclosure requirements. The Company follows a three-level hierarchy, prioritizing and defining the types of inputs used to measure fair value. The fair values of the natural gas, crude oil price swaps and natural gas liquid swaps are designated
as Level 3. The following fair value hierarchy table presents information about the Company’s assets and liabilities measured at fair value on a recurring basis at June 30, 20182019 and December 31, 2017:2018:
June 30, 2018 | Quoted Prices in Active Markets For Identical Assets (Level 1) | Significant Other Observable Inputs (Level 2) | Significant Unobservable Inputs (Level 3) | Balance at June 30, 2018 | ||||||||||||||||||||||||||||
June 30, 2019 | Quoted Prices in Active Markets For Identical Assets (Level 1) | Significant Other Observable Inputs (Level 2) | Significant Unobservable Inputs (Level 3) | Balance at June 30, 2019 | ||||||||||||||||||||||||||||
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Assets | ||||||||||||||||||||||||||||||||
Commodity derivative contracts | $ | — | $ | — | $ | 92 | $ | 92 | $ | — | $ | — | $ | 1,081 | $ | 1,081 | ||||||||||||||||
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Total assets | — | $ | — | $ | 92 | $ | 92 | — | $ | — | $ | 1,081 | $ | 1,081 | ||||||||||||||||||
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Liabilities | ||||||||||||||||||||||||||||||||
Commodity derivative contracts | $ | — | $ | — | $ | (9,083 | ) | $ | (9,083 | ) | $ | — | $ | — | $ | (1,675 | ) | $ | (1,675 | ) | ||||||||||||
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Total liabilities | $ | — | $ | — | $ | (9,083 | ) | $ | (9,083 | ) | $ | — | $ | — | $ | (1,675 | ) | $ | (1,675 | ) | ||||||||||||
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December 31, 2017 | 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, 2017 | ||||||||||||||||||||||||||||
December 31, 2018 | 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, 2018 | ||||||||||||||||||||||||||||
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Assets | ||||||||||||||||||||||||||||||||
Commodity derivative contracts | $ | — | $ | — | $ | 388 | $ | 388 | $ | — | $ | — | $ | 2,394 | $ | 2,394 | ||||||||||||||||
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Total assets | $ | — | $ | — | $ | 388 | $ | 388 | $ | — | $ | — | $ | 2,394 | $ | 2,394 | ||||||||||||||||
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Commodity derivative contract | $ | — | $ | — | $ | (3,422 | ) | $ | (3,422 | ) | $ | — | $ | — | $ | (98 | ) | $ | (98 | ) | ||||||||||||
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Total liabilities | $ | — | $ | — | $ | (3,422 | ) | $ | (3,422 | ) | $ | — | $ | — | $ | (98 | ) | $ | (98 | ) | ||||||||||||
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The derivative contracts were measured based on quotes from the Company’s counterparties. Such quotes have been derived using valuation models that consider various inputs including current market and contractual prices for the underlying instruments, quoted forward prices for natural gas , crude oil, natural gas liquids, volatility factors and interest rates, such as a LIBOR curve for a similar length of time as the derivative contract term as applicable. These estimates are verified using comparable NYMEX futures contracts or are compared to multiple quotes obtained from counterparties for reasonableness.
The significant unobservable inputs for Level 3 derivative contracts include basis differentials and volatility factors. An increase (decrease) in these unobservable inputs would result in an increase (decrease) in fair value, respectively. The Company does not have access to the specific assumptions used in its counterparties’ valuation models. Consequently, additional disclosures regarding significant Level 3 unobservable inputs were not provided.
The following table sets forth a reconciliation of changes in the fair value of financial assets and liabilities classified as Level 3 in the fair value hierarchy for the six months ended June 30, 2018.2019.
(Thousands of dollars) | ||||||||
Net Liabilities – December 31, 2017 | $ | (3,034 | ) | |||||
Total realized and unrealized gains (losses): | ||||||||
Net Asset– December 31, 2018 | $ | 2,296 | ||||||
Total realized and unrealized (gains) losses: | ||||||||
Included in earnings (a) | (7,533 | ) | (3,663 | ) | ||||
Purchases, sales, issuances and settlements | 1,576 | 773 | ||||||
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Net Liabilities – June 30, 2018 | $ | (8,991 | ) | |||||
Net Liabilities June 30, 2019 | $ | (594 | ) | |||||
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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. |
Derivative Instruments:
The Company is exposed to commodity price and interest rate risk, and management considers periodically the Company’s exposure to cash flow variability resulting from the commodity price changes and interest rate fluctuations. Futures, swaps and options are used to manage the Company’s exposure to commodity price risk inherent in the Company’s oil and gas production operations.
The Company does not apply hedge accounting to any of its commodity based derivatives. Both realized and unrealized gains and losses associated with commodity derivative instruments are recognized in earnings.
Interest rate swap derivatives are treated as cash-flow hedges and are used to fix our floating interest rates on existing debt. The value of interest rate swaps if applicable, would be recorded in accumulated other comprehensive loss, net of tax. There are no current interest rate swaps for the periods ending June 30, 2019 and December 31, 2018.
The following table sets forth the effect of derivative instruments on the consolidated balance sheets at June 30, 20182019 and December 31, 2017:2018:
Fair Value | ||||||||||||
(Thousands of dollars) | Balance Sheet Location | June 30, 2018 | December 31, 2017 | |||||||||
Asset Derivatives: | ||||||||||||
Derivatives not designated as cash-flow hedging instruments: | ||||||||||||
Natural gas commodity contracts | Other Current Assets | $ | 61 | $ | — | |||||||
Natural gas liquid contracts | Other Current Assets | 7 | — | |||||||||
Crude oil commodity contracts | Other Current Assets | — | 344 | |||||||||
Natural gas commodity contracts | Other Assets | 18 | 44 | |||||||||
Natural gas liquid contracts | Other Assets | 6 | — | |||||||||
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Total | $ | 92 | $ | 388 | ||||||||
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Liability Derivatives: | ||||||||||||
Derivatives not designated as cash-flow hedging instruments: | ||||||||||||
Crude oil commodity contracts | Derivative liability short-term | (5,503 | ) | (1,504 | ) | |||||||
Natural gas commodity contracts | Derivative liability short-term | (24 | ) | (4 | ) | |||||||
Natural gas liquid contracts | Derivative liability short-term | (189 | ) | — | ||||||||
Crude oil commodity contracts | Derivative liability long-term | (3,343 | ) | (1,910 | ) | |||||||
Natural gas commodity contracts | Derivative liability long-term | (3 | ) | (4 | ) | |||||||
Natural gas liquid contracts | Derivative liability long-term | (21 | ) | — | ||||||||
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| |||||||||
Total | $ | (9,083 | ) | $ | (3,422 | ) | ||||||
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Total derivative instruments | $ | (8,991 | ) | $ | (3,034 | ) | ||||||
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Fair Value | ||||||||||||
(Thousands of dollars) | Balance Sheet Location | June 30, 2019 | December 31, 2018 | |||||||||
Asset Derivatives: | ||||||||||||
Derivatives not designated as cash-flow hedging instruments: | ||||||||||||
Natural gas commodity contracts | Derivative asset short-term | $ | 136 | $ | 63 | |||||||
Natural gas liquid contracts | Derivative asset short-term | $ | 185 | $ | 138 | |||||||
Crude oil commodity contracts | Derivative asset short-term | $ | 760 | $ | 1,473 | |||||||
Natural gas commodity contracts | | Derivative asset long-term and other assets | | $ | — | $ | 7 | |||||
Crude oil commodity contracts | | Derivative asset long-term and other assets | | — | 713 | |||||||
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|
| |||||||||
Total | $ | 1,081 | $ | 2,394 | ||||||||
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Liability Derivatives: | ||||||||||||
Derivatives not designated as cash-flow hedging instruments: | ||||||||||||
Crude oil commodity contracts | Derivative liability short-term | $ | (1,675 | ) | $ | — | ||||||
Natural gas commodity contracts | Derivative liability short-term | — | (75 | ) | ||||||||
Natural gas liquid contracts | Derivative liability short-term | — | (13 | ) | ||||||||
Natural gas commodity contracts | Derivative liability long-term | — | (10 | ) | ||||||||
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|
| |||||||||
Total | $ | (1,675 | ) | $ | (98 | ) | ||||||
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| |||||||||
Total derivative instruments | $ | (594 | ) | $ | 2,296 | |||||||
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The following table sets forth the effect of derivative instruments on the consolidated statements of operations for the six monthsix-month period ended June 30, 20182019 and 2017:2018:
Location of gain (loss) recognized in income | Amount of gain (loss) recognized in income | Location of gain (loss) recognized in income | Amount of gain/loss recognized in income | |||||||||||||||||
(Thousands of dollars) | 2018 | 2017 | 2019 | 2018 | ||||||||||||||||
Derivatives not designated as cash-flow hedge instruments: | ||||||||||||||||||||
Natural gas commodity contracts | Unrealized (loss) gain on derivative instruments, net | $ | (328 | ) | $ | 1,852 | Unrealized gain (loss) on derivative instruments, net | $ | 151 | $ | (328 | ) | ||||||||
Crude oil commodity contracts | Unrealized (loss) gain on derivative instruments, net | $ | (5,432 | ) | 2,502 | Unrealized loss on derivative instruments, net | (3,101 | ) | (5,432 | ) | ||||||||||
Natural gas liquids contracts | Unrealized gain on derivative instruments, net | (197 | ) | — | Unrealized gain (loss) on derivative instruments, net | 60 | (197 | ) | ||||||||||||
Natural gas commodity contracts | Realized (loss) on derivative instruments, net | 85 | (205 | ) | Realized (loss) gain on derivative instruments, net | (8 | ) | 85 | ||||||||||||
Crude oil commodity contracts | Realized (loss) on derivative instruments, net | (1,634 | ) | (— | ) | Realized loss on derivative instruments, net | (876 | ) | (1,634 | ) | ||||||||||
Natural gas liquids contracts | Realized gain on derivative instruments, net | (27 | ) | — | Realized gain (loss) on derivative instruments, net | 111 | (27 | ) | ||||||||||||
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$ | (7,533 | ) | $ | 4,149 | $ | (3,663 | ) | $ | (7,533 | ) | ||||||||||
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(11) Earnings Per Share:
Basic earnings per share are computed by dividing earnings available to common stockholders by the weighted average number of common shares outstanding during the period. Diluted earnings per share reflect per share amounts that would have resulted if dilutive potential common stock had been converted to common stock in gain periods. The following reconciles amounts reported in the financial statements:
Six Months Ended June 30, | Six Months Ended June 30, | |||||||||||||||||||||||||||||||||||||||||||||||
2018 | 2017 | 2019 | 2018 | |||||||||||||||||||||||||||||||||||||||||||||
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 | 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 | $ | 2,726 | 2,119,343 | $ | 1.29 | $ | 22,659 | 2,241,310 | $ | 10.11 | $ | 2,737 | 2,031,569 | $ | 1.35 | $ | 2,726 | 2,119,343 | $ | 1.29 | ||||||||||||||||||||||||||||
Effect of dilutive securities: | ||||||||||||||||||||||||||||||||||||||||||||||||
Options | 753,404 | 751,019 | 761,169 | 753,404 | ||||||||||||||||||||||||||||||||||||||||||||
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Diluted | $ | 2,726 | 2,873,347 | $ | 0.95 | $ | 22,659 | 2,992,329 | $ | 7.57 | $ | 2,737 | 2,792,738 | $ | 0.98 | $ | 2,726 | 2,872,747 | $ | 0.95 | ||||||||||||||||||||||||||||
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Three Months Ended June 30, | Three Months Ended June 30, | |||||||||||||||||||||||||||||||||||||||||||||||
2018 | 2017 | 2019 | 2018 | |||||||||||||||||||||||||||||||||||||||||||||
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 | 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 | $ | (560 | ) | 2,097,737 | $ | (0.27 | ) | $ | 361 | 2,199,750 | $ | 0.16 | $ | 5,775 | 2,026,119 | $ | 2.85 | $ | (560 | ) | 2,097,737 | $ | (0.27 | ) | ||||||||||||||||||||||||
Effect of dilutive securities: | ||||||||||||||||||||||||||||||||||||||||||||||||
Options (a) | 749,491 | 761,584 | ||||||||||||||||||||||||||||||||||||||||||||||
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Diluted | $ | (560 | ) | 2,097,737 | $ | (0.27 | ) | $ | 361 | 2,949,261 | $ | 0.12 | $ | 5,775 | 2,787,702 | $ | 2.07 | $ | (560 | ) | 2,097,737 | $ | (0.27 | ) | ||||||||||||||||||||||||
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(a) | The effect of the 767,500 outstanding stock option is anti-dilutive for the three months ended June 30, 2018 due to net loss for the period. |
This Report may contain statements relating to the future results of the Company that are considered “forward-looking statements” asstatements “as defined in the Private Securities Litigation Reform Act of 1995 (the “PSLRA”). In addition, certain statements may be contained in the Company’s future filings with the SEC, in press releases, and in oral and written statements made by or with the approval of the Company that are not statements of historical fact and constitute forward-looking statements within the meaning of the PSLRA. Such forward-looking statements, in addition to historical information, which involve risk and uncertainties, are based on the beliefs, assumptions and expectations of management of the Company. Words such as “expects”, ‘believes”, “should”, “plans”, “anticipates”, “will”, “potential”, “could”, “intend”, “may”, “outlook”, “predict”, “project”, “would”, “estimates”, “assumes”, “likely” and variations of such similar expressions are intended to identify such forward-looking statements. These statements are not guarantees of future performance and involve risks and uncertainties and are based on a number of assumptions that could ultimately prove inaccurate and, therefore, there can be no assurance that they will prove to be accurate. Actual results and outcomes may vary materially from what is expressed or forecast in such statements due to various risks and uncertainties. These risks and uncertainties include, among other things, the possibility of drilling cost overruns and technical difficulties, volatility of oil and gas prices, competition, risks inherent in the Company’s oil and gas operations, the inexact nature of interpretation of seismic and other geological and geophysical data, imprecision of reserve estimates, and the Company’s ability to replace and expand oil and gas reserves. Accordingly, stockholders and potential investors are cautioned that certain events or circumstances could cause actual results to differ materially from those projected. The forward-looking statements are made as of the date of this Report and other than as required by the federal securities laws, the Company assumes no obligation to update the forward-looking statements or to update the reasons why actual results could differ from those projected in the forward-looking statements.
Item 2. | MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS |
The following discussion is intended to assist you in understanding our results of operations and our present financial condition. Our Condensed Consolidated Financial Statements and the accompanying Notes to the Condensed Consolidated Financial Statements included elsewhere in this Report contain additional information that should be referred to when reviewing this material.
OVERVIEW
We are an independent oil and natural gas company engaged in acquiring, developing and producing oil and natural gas. We presently own producing andnon-producing properties located primarily in Texas, Oklahoma and West Virginia. In addition, we own a substantial amount of well servicing equipment. All of our oil and gas properties and interests are located in the United States. Assets in our principal focus areas include mature properties with long-lived reserves and significant development opportunities as well as newer properties with development and exploration potential.
We are the operator of the majority of our developed and undeveloped acreage which is nearly all held by production. In the Permian Basin of West Texas and eastern New Mexico the Company maintains an acreage position of over 20,440approximately 19,830 gross (13,100(12,580 net) acres, approximately 95%97% of which is located in Reagan, Upton, Martin, and Midland counties of Texas where our current horizontal drilling activity is focused. Our West TexasRecent results from our wells and the wells of other operators have proven the potential of the Lower Spraberry, Jo Mill and Wolfcamp A intervals, in addition to the Middle Wolfcamp. We believe our Permian Basin acreage has significantthe resource potential into support the Spraberry and Wolfcamp reservoirs that we believe could support thefuture drilling of as many as 400 additional375 horizontal wells.
In Oklahoma we maintain an acreage position of approximately 82,01281,800 gross (10,947(10,900 net) acres. Our Oklahoma horizontal development is focused primarily in Canadian, Kingfisher, Grady, and Garvin counties. We believe approximately 2,2152,210 net acres in these counties hold significant additional resource potential that could support the drilling of as many as 73105 new horizontal wells based on an estimate of only twofour to eight wells per section with our share of such prospective futuredepending on the reservoir target area.
Future development being about $42 millionplans are established based on an average 10.5% ownership level.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 of December 31, 2017.2018.
Appalachian | Gulf Coast | Mid- Continent | West Texas | Other | Total | Appalachian | Gulf Coast | Mid- Continent | West Texas | Other | Total | |||||||||||||||||||||||||||||||||||||
Proved Reserves as of December 31, 2017 (MBoe) | ||||||||||||||||||||||||||||||||||||||||||||||||
Proved Reserves as of December 31, 2018 (MBoe) | ||||||||||||||||||||||||||||||||||||||||||||||||
Developed | 537 | 803 | 1,774 | 6,742 | 37 | 9,893 | 559 | 814 | 2,839 | 8,401 | 8 | 12,622 | ||||||||||||||||||||||||||||||||||||
Undeveloped | — | — | 132 | 647 | — | 779 | — | — | 43 | — | — | 43 | ||||||||||||||||||||||||||||||||||||
Total | 537 | 803 | 1,906 | 7,389 | 37 | 10,672 | 559 | 814 | 2,882 | 8,401 | 8 | 12,665 | ||||||||||||||||||||||||||||||||||||
Gross Productive Wells (Working Interest and ORRI wells) | 557 | 322 | 619 | 566 | 156 | 2,220 | ||||||||||||||||||||||||||||||||||||||||||
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) | 489 | 281 | 471 | 523 | 94 | 1,858 | 500 | 263 | 430 | 519 | 45 | 1,757 | ||||||||||||||||||||||||||||||||||||
Net Productive Wells | 456 | 174 | 257 | 516 | 23 | 1,426 | ||||||||||||||||||||||||||||||||||||||||||
Net Productive Wells (Working Interest Only) | 469 | 164 | 227 | 256 | 4 | 1,120 | ||||||||||||||||||||||||||||||||||||||||||
Gross Operated Productive Wells | 467 | 244 | 348 | 370 | 57 | 1,486 | 476 | 211 | 243 | 354 | — | 1,284 | ||||||||||||||||||||||||||||||||||||
Gross Operated Water Disposal, Injection and Supply wells | 1 | 8 | 64 | 7 | 1 | 81 | 1 | 9 | 67 | 7 | — | 84 |
In several of our regions we operate 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.
West Texas Region
Our West Texas activities are concentrated in the Permian Basin in Texas and New Mexico. The Spraberry field was discovered in 1949, encompasses eight counties in West Texas and the Company believes it is the second largest oil field in the 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 six formations; the Upper and Lower Spraberry, the Wolfcamp, the Strawn and the Atoka, at depths ranging from 6,700 feet to 11,300 feet. This region is managed from our office in Midland, Texas. As of December 31, 2018, we had 519 wells (256 net) in the West Texas area, of which 361 wells are operated by us. Principal producing intervals for the
Company are in the Spraberry, Jo Mill, Wolfcamp and San Andres formations at depths ranging from 5,500 to 12,500 feet. Average net daily production in 2018 was 4,248 Boe. At December 31, 2018, we had 8,401 MBoe of proved reserves in the West Texas area, or 66% of our total proved reserves. We maintain an acreage position of approximately 19,830 gross (12,580 net) acres in the Permian Basin in West Texas, primarily in Reagan, Upton, Martin and Midland counties and believe this acreage has significant resource potential for horizontal drilling in the Spraberry, Jo Mill, and Wolfcamp intervals. We operate a field service group in this region utilizing nine workover rigs, five hot oiler trucks, one kill truck and one roustabout truck. 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. In the first quarter of 2019, in our West Texas horizontal drilling program, the Company participated for 49.3% interest in eightone-mile horizontal wells drilled in the Middle Wolfcamp. These wells were brought on production in February, 2019. The total cost of these eight wells and their facilities is approximately $50.6 million, with the Company’s share being $24.9 million. Since completion these wells will have produced approximately 600,000 barrels of oil, along with associated gas. PrimeEnergy’s net revenue interest is 36.82%, therefore, our share of the oil recovered in just the first six months is approximately 212,500 barrels. We are pleased with the economic performance of these eight wells and expect 100% capital recover in less than two years.
In the second quarter of 2019, in our West Texas horizontal drilling program, we completed three new horizontal wells in intervals above the Middle Wolfcamp that previously were not proven as horizontal target reservoirs for our acreage. In the first 60 days of production the three wells have produced 125,000 gross barrels of oil along with associated wellhead gas: 50,000 barrels from the Lower Spraberry, 46,000 barrels from the Jo Mill, and 31,000 barrels from the Upper Wolfcamp. PrimeEnergy has 49% working interest and 40.7% net revenue interest in the Lower Spraberry well, 47% working interest and 39% net revenue interest in the Jo Mill well and 5.3% working interest and 3.9% net revenue interest in the Upper Wolfcamp well. Our share of the gross $26 million cost of these three wells is approximately $8.9 million.
These three new horizontal wells in Upton County are important tests of the economic viability of the shallower target zones, both for the 1,300 acre block in which they were drilled, as well as for our nearby 2,600 leasehold AMI (Area of Mutual Interest) acreage with Apache that holds similar potential. The successful outcome hasproven-up 21 additional locations in the 1,300 acre block, making these locations more likely to be drilled in the near future. The gross cost of an additional 21 wells would be approximately $182 million, with the Company’s share being $60 million. In the nearby Apache AMI, Prime holds several leases with interest varying from 14% to 56%. The strong performance of these new horizontals is likely to spur the drilling of as many as 96 additional horizontal wells in the Apache AMI over the coming years. The gross cost of 96 wells here would be approximately $748 million with the Company’s share being approximately $284 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 Permian Basin of West Texas the Company maintains an acreage position of approximately 19,830 gross (12,580 net) acres primarily in Reagan, Upton, Martin and Midland counties. We believe this acreage has significant resource potential in approximately 10 reservoir benches, including benches of the Spraberry, Jo Mill, and Wolfcamp formations to support the potential for drilling as many as 375 additional horizontal wells.
Mid-Continent Region
OurMid-Continent activities are concentrated in central Oklahoma. This region is managed from our office in Oklahoma City, Oklahoma. As of December 31, 2018, we had 580 wells (227 net) in theMid-Continent area, of which 310 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 2018 was 977 Boe. At December 31, 2018, we had 2,882 MBoe of proved reserves in theMid-Continent area, or 23% of our total proved reserves. We maintain an acreage position of approximately 81,800 gross (10,900 net) acres in this region, primarily in Canadian, Kingfisher, Grant and Garvin counties. We operate a field service group in this region from a field office in Elmore City, utilizing one workover rig and one saltwater hauling truck. OurMid-Continent region is actively participating with third-party operators in the horizontal development of lands that include Company owned interest in several counties in the STACK and SCOOP shale plays of Oklahoma where drilling is primarily targeting reservoirs of the Mississippian, Woodford, and Hunton formations.
In theMid-Continent Region, in 2018, the Company participated in 11 wells in Oklahoma, with six of these on production byyear-end. Another five of the 11 wells were drilled by Marathon in the “Ruthie 1609” tract in Kingsfisher County and broughton-line in March of 2019. Prime participated with 11.87% interest in these five new wells, investing approximately $4.9 million. This group of wells is showing strong initial production performance. This activity has now been closely followed by the
proposed drilling of 19 new wells by Encana Corporation in nearby leases in which PrimeEnergy has an average of 7.05% interest. Twelve of these wells were spud in June 2019 and the Company has agreed to participate for its average interest in these wells of 4.9% interest. Drilling and completion costs of these 19 wells net to our interest are expected to be $9.3 million. Also in Oklahoma, the Company recently participated with Roane Resources, Inc. in the drilling of seven wells in Grady County, Oklahoma. The Company has 10% interest in one of these seven wells and less than one percent interest in the remaining six. These wells were included as Proved Undeveloped in the 2018year-end reserve report. The estimated total expenditure net to the Company is approximately $1.46 Million. Three of these seven wells came on line July, 2019 and we anticipate the other four wells will also be completed and put into production in the third quarter of 2019. In addition, there are eight new wells spud in the first and second quarter of 2019 from which the Company will receive a minor over-riding royalty interest.
The Company’s horizontal activity in Oklahoma is primarily focused in Canadian, Grady, Kingfisher, and Garvin counties where we have approximately 2,210 net leasehold acres within the SCOOP/STACK shale plays. We believe this acreage has significant additional resource potential that could support the drilling of as many as 105 new horizontal wells based on an estimate of eight wells per section: four in the Mississippian and four in the Woodford Shale.
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 June 30, 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.
Gulf Coast Region
Our development, exploitation, exploration and production activities in the Gulf Coast region are primarily concentrated in southeast Texas. This region is managed from our office in Houston, Texas. Principal producing intervals are in the Wilcox, San Miguel, Olmos, and Yegua formations at depths ranging from 3,000 to 12,500 feet. We had 263 producing wells (164 net) in the Gulf Coast region as of December 31, 2018, of which 220 wells are operated by us. Average daily production in 2018 was 572 Boe.
At December 31, 2018, we had 925 MBoe of proved reserves in the Gulf Coast region, which represented 6% of our total proved reserves. We maintain an acreage position of over 12,700 gross (5,120 net) acres in this region, primarily in Dimmit and Polk counties. We operate a field service group in this region from a field office in Carrizo Springs, Texas utilizing four workover rigs, nineteen water transport trucks, two saltwater disposal wells 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 of June 30, 2019, the Gulf Coast region has no operated wells in the process of being drilled, no waterfloods in the process of being installed and no other related activities of material importance.
Reserve Information:
Our interests in proved developed and undeveloped oil and gas properties, including the interests held by the Partnerships, have been evaluated by Ryder Scott Company, L.P. for each of the three years ended December 31, 2018. 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 ouryear-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 over ten 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’s degree in Geology and an MBA in finance and is a member of the Society of Petroleum Engineers and American Association of Petroleum Geologist.
All of our reserves are located within the continental United States. The following table summarizes our oil and gas reserves at each of the respective dates:
Reserve Category | Reserve Category | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Proved Developed | Proved Undeveloped | Total | 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) | Oil (MBbls) | NGLs (MBbls) | Gas (MMcf) | Total (MBoe) | Oil (MBbls) | NGLs (MBbls) | Gas (MMcf) | Total (MBoe) | Oil (MBbls) | NGLs (MBbls) | Gas (MMcf) | Total (MBoe) | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
(a) | (a) | (a) | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
2015 | 4,579 | 1,673 | 23,275 | 10,131 | 52 | 12 | 55 | 73 | 4,631 | 1,685 | 23,330 | 10,204 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
2016 | 3,107 | 1,265 | 13,001 | 6,539 | 643 | 159 | 2,003 | 1,135 | 3,750 | 1,424 | 15,004 | 7,674 | 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 | 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 |
(a) | In computing total reserves on a barrels of oil equivalent (Boe) |
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. In addition, we had an increase in reserves from overriding royalty interest in nine horizontal wells drilled in Oklahoma by other operators.
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 six horizontal wells in Oklahoma. Proved Developed reserves atyear-end included an additional eightShut-In horizontal wells in West Texas that have been brought on production in February, 2019 and fiveShut-In horizontal wells in Oklahoma brought on production in March, 2019. In addition, at December 31, 2018, our reserve report included 43 MBoe of proved undeveloped reserves attributable to eight horizontal wells drilled in Oklahoma. These eight wells are expected to be completed and put on production in the second and third quarters of 2019. Additional 2019 activity is discussed in the Recent Activities section below.
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.
The estimated future net revenue (using current prices and costs as of those dates) and the present value of future net revenue (at a 10% discount for estimated timing of cash flow) for our proved developed and proved undeveloped oil and gas reserves at the end of each of the three years ended December 31, 2017,2018, are summarized as follows (in thousands of dollars):
Proved Developed | Proved Undeveloped | Total | 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 | 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 | ||||||||||||||||||||||||||||||||||||||||||||||||
2015 | $ | 70,834 | $ | 60,962 | $ | 1,098 | $ | 233 | $ | 71,932 | $ | 61,195 | $ | 2,393 | $ | 58,802 | ||||||||||||||||||||||||||||||||||||||||||||||||
2016 | $ | 56,467 | $ | 46,827 | $ | 18,114 | $ | 10,403 | $ | 74,581 | $ | 57,230 | $ | 4,993 | $ | 52,237 | $ | 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 | $ | 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 |
The PV 10 Value represents the discounted future net cash flows attributable to our proved oil and gas reserves before income tax, discounted at 10%. Although this measure is not in accordance with U.S. generally accepted accounting principles (“GAAP”), we believe that the presentation of the PV 10 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 PV 10 of future income taxes represents the sole reconciling item between thisnon-GAAP PV 10 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 major expenditure is required before the well is put on production. Our reserves include amounts attributable tonon-controlling interests in the Partnerships. These interests represent less than 3% of our reserves.
In accordance with SEC rules governingU.S. generally accepted accounting principles, product prices are determined using the schedulingtwelve-month average oil and gas index prices, calculated as the unweighted arithmetic average for the first day of the drillingmonth price for each month, adjusted for oilfield or gas gathering hub and wellhead price differentials (e.g. grade, transportation, gravity, sulfur, and basic sediment and water) as appropriate. Also in accordance with SEC specifications and U.S. generally accepted accounting principles, changes in market prices subsequent to December 31 are not considered.
While it may reasonably be anticipated that the prices received for the sale of PUD reservesour production may be higher or lower than the prices used in this evaluation, as described above, and the operating costs relating to such production may also increase or decrease from existing levels, such possible changes in prices and costs were, in accordance with rules adopted by the SEC, omitted from consideration in making this evaluation for the SEC case. Actual volumes produced, prices received and costs incurred may vary significantly from the SEC case.
Natural gas prices, based on the twelve-month average of the first of the month Henry Hub index price, were $3.10 per MMBtu in 2018 as compared to $2.98 per MMBtu in 2017 and $2.49 per MMBtu in 2016. Oil prices, based on the NYMEX first of the month average price, were $65.56 per barrel in 2018 as compared to $51.34 per barrel in 2017, and $42.75 per barrel in 2016. Since January 1, 2019, we have onlynot filed any estimates of our oil and gas reserves with, nor were any such estimates included in ouryear-end reserve reportany reports to, any federal authority or agency, other than the 22 PUD locations for which we have definitive plans to drill. The Company has a working interest in eight of these PUD locationsSecurities and an overriding royalty interest only in the remaining fourteen locations. Currently all 22 of these PUD locations have been drilled, 13 are producing and the remainder are awaiting completion.Exchange Commission.
Our balanced portfolio of assets positions us well for both the current commodity price environment and future potential upside as we develop our attractive resource opportunities. Our primary sources of liquidity are cash flows generated from operations, through our producing oil and gas properties, our field services business, and from sales ofnon-core acreage.
The Company will continue to pursue the acquisition of leasehold acreage and producing properties in areas where we currently operate and believe there is additional exploration and development potential and will attempt to assume the position of operator in all such acquisitions. In order 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 so as 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 may 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.
Maintaining a strong balance sheet and ample liquidity are key components of our business strategy. For 2018,2019, we will continue our focus on preserving financial flexibility and ample liquidity as we manage the risks facing our industry. Our 20182019 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, divestnon-strategic assets, or enter into strategic joint ventures.
RECENT ACTIVITIES
Since the start of our West Texas horizontal drilling program in 2015 and through the 2nd quarter of 2018, the Company has participated in 5667 horizontal wells and invested approximately $103 million dollars. The Company has an acreage position approximately 12,580 net acres in West Texas with the potential to drill 375 or more new horizontal wells. In Oklahoma, since the start in 2012 of our horizontal drilling program in the SCOOP/STACK shale plays, the Company has drilled or committed to drill 64 wells with a total investment of approximately $46 million dollars, plus has elected to receive an overriding royalty interest in 63 additional wells drilledto-date. The Company holds approximately 2,210 net acres within the SCOOP/STACK shale plays with the potential for 105 new horizontal wells.
In 2018, the Company participated in a total of 28 gross (6.1 net) horizontal wells with an investment to our share of approximately $41 million. We completed 17 horizontal wells in West Texas. In 41 of these wells, the Company owns an average of 23.82% working interest and all 41 wells are on production. As to 15 wells of the 56 total, the Company participated with less than 1% working interest and these are also all on production. During 2017, the Company expended approximately $46.4 million in this program. Development of our West Texas resources continued in the first six months of 2018 with the drilling of threehorizontal development program and 11 horizontal wells in Upton County Texas. Theseour Scoop-Stack horizontal development program in Oklahoma. All 28 wells were recently fracture stimulatedsuccessful and asare producing.
In the first quarter of July 1, have all been placed on production. Development plans for the second half of 2018 include drilling an additional 11 horizontal wells. This additional activity will bring the total drilling to 14 horizontal wells in 20182019, in our West Texas horizontal drilling program.program, the Company participated for 49.3% interest in eightone-mile horizontal wells drilled in the Middle Wolfcamp. These wells were brought on production in February, 2019. The total cost of these eight wells and their facilities is approximately $50.6 million, with the Company’s share being $24.9 million. Since completion these wells will have produced approximately 600,000 barrels of oil, along with associated gas. PrimeEnergy’s net revenue interest is 36.82%, therefore, our share of the oil recovered in just the first six months is approximately 212,500 barrels. We are pleased with the economic performance of these eight wells and expect 100% capital recover in less than two years.
In Upton County, Texas, we are developing a contiguous 3,900 acre block with our joint venture partner, Apache Corporation. Within this acreage block, the Company has 2,606 leasehold acres with interest between 14% and 56%, depending on the formation being developed. Through the 2ndsecond quarter of 2018, twenty-five2019, in our West Texas horizontal drilling program, we completed three new horizontal wells in intervals above the Middle Wolfcamp that previously were not proven as horizontal target reservoirs for our acreage. In the first 60 days of production the three wells have been drilledproduced 125,000 gross barrels of oil along with associated wellhead gas: 50,000 barrels from the Lower Spraberry, 46,000 barrels from the Jo Mill, and completed in this joint venture, including three wells completed31,000 barrels from the Upper Wolfcamp. PrimeEnergy has 49% working interest and put on production as of July 1, 2018. The Company has a 38.25%40.7% net revenue interest in eachthe Lower Spraberry well, 47% working interest and 39% net revenue interest in the Jo Mill well and 5.3% working interest and 3.9% net revenue interest in the Upper Wolfcamp well. Our share of the gross $26 million cost of these three wells andis approximately $8.9 million.
These three new horizontal wells in Upton County are important tests of the economic viability of the shallower target zones, both for the 1,300 acre block in which they were drilled, as well as for our netnearby 2,600 leasehold AMI acreage with Apache that holds similar potential. The successful outcome hasproven-up 21 additional locations in the 1,300 acre block, making these locations more likely to be drilled in the near future. The gross cost willof an additional 21 wells would be approximately $10.1$182 million, with the Company’s share being $60 million. In the nearby Apache Corporation has indicated plansAMI, Prime holds several leases with interest varying from 14% to continue PAD drilling56%. The strong performance of the acreage with future phases of development expectedthese new horizontals is likely to result inspur the drilling of approximatelyas many as 96 additional horizontal wells at ain the Apache AMI over the coming years. The gross cost of about96 wells here would be approximately $748 million. Themillion with the Company’s share of these capital expenditures would bebeing approximately $284 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. Also in Upton County,
In the Permian Basin of West Texas the Company is developing a separate 1,310 acre block with Apache Corporation as operator. Plans for the second halfmaintains an acreage position of 2018 include the drilling of three new horizontal wells exploring landing-zones outsideapproximately 19,830 gross (12,580 net) acres primarily in Reagan, Upton, Martin and Midland counties. We believe this acreage has significant resource potential in approximately 10 reservoir benches, including benches of the Middle Wolfcamp. The grossSpraberry, Jo Mill, and Wolfcamp formations to support the potential for drilling and completion costs will be approximately $23 million. Prime holds between 28% and 48% working interest in various depths of this acreage and our share of these three wells will be approximately $11 million. With favorable results from these three wells anas many as 375 additional 21 wells would likely be drilled in the near future at a gross cost of approximately $172 million with the Company’s share being approximately $71 million.horizontal wells.
In Martin County, Texas we are developing a 960 acre block with RSP Permian. In 2016, two wells were drilled and completed and two additional wells were drilled and brought on lineOklahoma, in 2017. The Company owns 35% to 38% interest in the acreage of this joint venture where RSP Permian is the operator. No near-term plans have been received from RSP Permian, however, offset operators have been actively drilling and their results appear encouraging for the future development of multiple landing zones within this acreage block.
With regard to our Oklahoma horizontal development program, which began in 2012, the Company has participated in 30 horizontal wells for approximately $28 million through June, 2018. Over this same time period the Company chose to retain an overriding royalty interest in 28 other horizontal wells that were drilled. In the first half of 2018, the Company participated in two horizontal11 wells, operatedwith six of these on production by Linn Operatingyear-end. Five of these wells, drilled by Marathon in the “Ruthie 1609” tract in Kingsfisher County, were broughton-line in March of 2019. Prime participated with 11.87% interest in these five new wells, investing approximately $4.9 million. This group of wells is showing strong initial production performance. This activity has now been closely followed by the proposed drilling of 19 new wells by
Encana Corporation in nearby leases in which PrimeEnergy has an average of 7.05% interest. Twelve of these wells were spud in June 2019 and the Company has agreed to participate for its average interest in these wells of 4.9% interest. Drilling and completion costs of these 19 wells net to our interest are expected to be $9.3 million.
Also in Oklahoma, the Company recently participated with Roane Resources, Inc. in the drilling of seven wells in Grady County, Oklahoma. The Company holdshas 10% interest in one wellof these seven wells and 1%less than one percent interest in the other.remaining six. The cost for these wellsestimated total expenditure net to the Company is approximately $14,703,000, with our net share being $828,000. Both$1.46 Million. Three of these seven wells have been drilled,came on line July, 2019 and we anticipate the other four wells will also be completed and placed on production. Alsoput into production in 2018,the third quarter of 2019. In addition, there are eight new wells spud in the first and second quarter of 2019 from which the Company elected to retain an ORRI in 16 wells that are in the process of being drilled or completed in various counties of central Oklahoma. In the second half of 2018 the Company anticipates participating in the drilling of as many as five additionalwill receive a minor over-riding royalty interest.
The Company’s horizontal wells in central Oklahoma with interest between 6% and 12%. The horizontal activity on Company acreage in Oklahoma is primarily focused in Canadian, Grady, Kingfisher, and Garvin counties where we have approximately 2,2152,210 net acres.leasehold acres within the SCOOP/STACK shale plays. We believe this acreage has significant additional resource potential that could support the drilling of 73as many as 105 new horizontal wells based on an estimate of only twoeight wells per section with our share of the capital expenditure being about $42 million at an average 10.5% ownership level. We recently received Authorizations for Expenditures forsection: four horizontal wells in Kingfisher county from the operator, Marathon Oil. Our share of this drilling will be approximately $5 million.
In the first half of 2018, in the Gulf Coast region of Texas, Unit Petroleum drilledMississippian and completed two successful wellsfour in the Wilcox Formation of the Segno Deep field in Polk County. The Company has a 3.87% overriding royalty interest in each of these wells.Woodford Shale.
RESULTS OF OPERATIONS
20182019 and 20172018 Compared
We reported anet income of $2.7 million, or $1.35 per share and $5.8 million, or $2.85 per share for the six and three months ended June 30, 2019, respectively, as compared to net income for the six months ended June 30, 2018 of $2.7 million, or $1.29 per share and a net loss for the three months ended June 30, 2018 of $0.6 million, or $0.27 per share, as compared to net income of $22.7 million, or $10.11 per share and $0.4 million, or $0.16 per share for the six and three months ended June 30, 2017, respectively.share. Current year net income reflects an increase in production combined with commodity price changes over the three and six months ended June 30, 2018,2019, decrease in gains related to the sale of acreage and changes related to the valuation of derivative instruments. The significant components of income and expense are discussed below.
Oil, gas and NGLs sales increased $7.7$1.7 million, or 55%8% from $14.0 million for the three months ended June 30, 2017 to $21.7 million for the three months ended June 30, 2018 and increased $20.3 million, or 77% from $26.4to $23.4 million for the sixthree months ended June 30, 2017 to2019 and increased $0.5 million, or 1% from $46.8 million for the six months ended June 30, 2018.2018 to $47.2 million for the six months ended June 30, 2019.
Our realized prices at the well head increaseddecreased an average of $18.39$4.52 per barrel, or 41%7% and $15.72$7.04 per barrel, or 33%11% on crude oil during the three and six months ended June 30, 2018,2019, respectively from the same periods in 2017.2018. Our average price for natural gas decreased $0.95$1.01 per Mcf, or 32%49% and $0.72$0.73 per Mcf, or 24%31% during the three and six months ended June 30, 2018,2019, respectively from the same periods in 2017.2018. Our average price for NGLs sold increaseddecreased an average of $4.06$11.15 per barrel, or 17%41% and $5.23$8.61 per barrel, or 24%32% during the three and six months ended June 30, 2018,2019, respectively from the same periods in 2017.2018. Production increases were negatively impacted by natural gas prices at the Waha hub where Permian Basin production exceeded West Texas takeaway capacity. Gas prices traded at historic lows, and at times were negative, for portions of the second quarter of 2019. This gas pricing is expected to continue until Waha prices improve, which is anticipated when the third-party operated Gulf Coast Express (GCX) pipeline enters service in late September.
Our crude oil production increased by 35,00071,000 barrels or 15%27% from 226,000 barrels for the second quarter 2017 to 261,000 barrels for the second quarter 2018 to 332,000 barrels for the second quarter 2019 and increased by 183,000104,000 barrels, or 46%18% from 401,000 barrels for the six months ended June 30, 2017 to 584,000 barrels for the six months ended June 30, 2018. Our natural gas production increased by 19,000 Mcf, or 1.8% from 1,079,000 Mcf for the second quarter 20162018 to 1,060,000 Mcf for the second quarter 2017 and increased by 177,000 Mcf, or 10% from 1,694000 Mcf688,000 barrels for the six months ended June 30, 20172019. Our natural gas production increased by 331,000 Mcf, or 34% from 964,000 Mcf for the second quarter 2018 to 1,295,000 Mcf for the second quarter 2019 and increased by 372,000 Mcf, or 20% from 1,871,000 Mcf for the six months ended June 30, 2018. Our NGL production increased by 76,000 barrels or 50.7% from 150,000 barrels for the second quarter 20162018 to 226,000 barrels for the second quarter 2017 and increased by 103,000 barrels, or 94% from 110,000 barrels2,243,000 Mcf for the six months ended June 30, 20172019. Our NGL production increased by 33,000 barrels or 29% from 113,000 barrels for the second quarter 2018 to 146,000 barrels for the second quarter 2019 and increased by 75,000 barrels, or 35% from 213,000 barrels for the six months ended June 30, 2018.2018 to 288,000 barrels for the six months ended June 30, 2019. The net increase in production volumes reflect by production from our Upton county horizontalnew wells added in late 2017,February through May 2019, offset with the natural decline of the previously existing properties. Production
The following table summarizes the primary components of production volumes and average sales prices realized for the three months ended June 30, 2019 and 2018 (excluding realized gains and losses from these horizontal wells was negatively affected in the second quarter of 2018 due toshut-ins and frac hits from completion activities on additional wells drilled in the first quarter of 2018 and completed in the second quarter. The affected wells have now returned topre-frac hit levels and the new wells were brought on production primarily in July 2018.derivatives).
Six months ended June 30, | Six months ended June 30, | |||||||||||||||||||||||||||||||
2018 | 2017 | Increase / (Decrease) | Increase / (Decrease) | 2019 | 2018 | Increase / (Decrease) | Increase / (Decrease) | |||||||||||||||||||||||||
Barrels of Oil Produced | 584,000 | 401,000 | 183,000 | 46 | % | 688,000 | 584,000 | 104,000 | 18 | % | ||||||||||||||||||||||
Average Price Received | $ | 62.88 | $ | 47.16 | $ | 15.72 | 33 | % | $ | 55.84 | $ | 62.88 | $ | (7.04 | ) | (11 | )% | |||||||||||||||
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Oil Revenue (In 000’s) | $ | 36,723 | $ | 18,911 | $ | 17,812 | 94 | % | $ | 38,442 | $ | 36,723 | $ | 1,719 | 5 | % | ||||||||||||||||
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Mcf of Gas Sold | 1,871,000 | 1,694,000 | 177,000 | 10 | % | 2,243,000 | 1,871,000 | 372,000 | 20 | % | ||||||||||||||||||||||
Average Price Received | $ | 2.33 | $ | 3.05 | $ | (0.72 | ) | (24 | )% | |||||||||||||||||||||||
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Gas Revenue (In 000’s) | $ | 4,352 | $ | 5,163 | $ | (811 | ) | (16 | )% | |||||||||||||||||||||||
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Barrels of Natural Gas Liquids Sold | 213,000 | 110,000 | 103,000 | 94 | % | |||||||||||||||||||||||||||
Average Price Received | $ | 26.75 | $ | 21.52 | $ | 5.23 | 24 | % | ||||||||||||||||||||||||
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Natural Gas Liquids Revenue (In 000’s) | $ | 5,698 | $ | 2,367 | $ | 3,331 | 141 | % | ||||||||||||||||||||||||
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Total Oil & Gas Revenue (In 000’s) | $ | 46,773 | $ | 26,441 | $ | 20,332 | 77 | % | ||||||||||||||||||||||||
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Three months ended June 30, | Six months ended June 30, | |||||||||||||||||||||||||||||||
2018 | 2017 | Increase / (Decrease) | Increase / (Decrease) | 2019 | 2018 | Increase / (Decrease) | Increase / (Decrease) | |||||||||||||||||||||||||
Barrels of Oil Produced | 261,000 | 226,000 | 35,000 | 15 | % | |||||||||||||||||||||||||||
Average Price Received | $ | 63.69 | $ | 45.30 | $ | 18.39 | 41 | % | ||||||||||||||||||||||||
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Oil Revenue (In 000’s) | $ | 16,622 | $ | 10,237 | $ | 6,385 | 62 | % | ||||||||||||||||||||||||
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Mcf of Gas Sold | 964,000 | 831,000 | 133,000 | 16 | % | |||||||||||||||||||||||||||
Average Price Received | $ | 2.06 | $ | 3.01 | $ | (0.95 | ) | (32 | )% | $ | 1.60 | $ | 2.33 | $ | (0.73 | ) | (31 | )% | ||||||||||||||
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Gas Revenue (In 000’s) | $ | 1,989 | $ | 2,505 | $ | (516 | ) | (21 | )% | $ | 3,590 | $ | 4,352 | $ | (762 | ) | (18 | )% | ||||||||||||||
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Barrels of Natural Gas Liquids Sold | 113,000 | 54,000 | 59,000 | 109 | % | 288,000 | 213,000 | 75,000 | 35 | % | ||||||||||||||||||||||
Average Price Received | $ | 27.42 | $ | 23.35 | $ | 4.06 | 17 | % | $ | 18.14 | $ | 26.75 | $ | (8.61 | ) | (32 | )% | |||||||||||||||
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Natural Gas Liquids Revenue (In 000’s) | $ | 3,098 | $ | 1,261 | $ | 1,837 | 146 | % | $ | 5,219 | $ | 5,698 | $ | (479 | ) | (8 | )% | |||||||||||||||
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Total Oil & Gas Revenue (In 000’s) | $ | 21,709 | $ | 14,003 | $ | 7,706 | 55 | % | $ | 47,251 | $ | 46,773 | $ | 478 | 1 | % | ||||||||||||||||
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Three months ended June 30, | ||||||||||||||||
2019 | 2018 | Increase / (Decrease) | Increase / (Decrease) | |||||||||||||
Barrels of Oil Produced | 332,000 | 261,000 | 71,000 | 27 | % | |||||||||||
Average Price Received | $ | 59.17 | $ | 63.69 | $ | (4.52 | ) | (7 | )% | |||||||
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Oil Revenue (In 000’s) | $ | 19,644 | $ | 16,622 | $ | 3,022 | 18 | % | ||||||||
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Mcf of Gas Sold | 1,295,000 | 964,000 | 331,000 | 34 | % | |||||||||||
Average Price Received | $ | 1.05 | $ | 2.06 | $ | (1.01 | ) | (49 | )% | |||||||
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Gas Revenue (In 000’s) | $ | 1,355 | $ | 1,989 | $ | (634 | ) | (32 | )% | |||||||
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Barrels of Natural Gas Liquids Sold | 146,000 | 113,000 | 33,000 | 29 | % | |||||||||||
Average Price Received | $ | 16.27 | $ | 27.42 | $ | (11.15 | ) | (41 | )% | |||||||
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Natural Gas Liquids Revenue (In 000’s) | $ | 2,375 | $ | 3,098 | $ | (723 | ) | (23 | )% | |||||||
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Total Oil & Gas Revenue (In 000’s) | $ | 23,374 | $ | 21,709 | $ | 1,665 | 8 | % | ||||||||
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Oil, Natural Gas and NGL DerivativesWe 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 asmark-to-market adjustments, are recognized as unrealized gains and losses in the accompanying condensed consolidated statements of operations. As oil and natural gas prices remain volatile,mark-to-market accounting treatment creates volatility in our revenues. The following table summarizes the results of our derivative instruments for the three and six months ended June 20172019 and 2018:
Three Months Ended June 30, | Six Months Ended June 30, | Three Months Ended June 30, | Six Months Ended June 30, | |||||||||||||||||||||||||||||
2018 | 2017 | 2018 | 2017 | 2019 | 2018 | 2019 | 2018 | |||||||||||||||||||||||||
($ in thousand) | ($ in thousand) | |||||||||||||||||||||||||||||||
Oil derivatives – realized gains (losses) | $ | (1,156 | ) | $ | 78 | $ | (1,634 | ) | $ | — | $ | (964 | ) | $ | (1,156 | ) | $ | (876 | ) | $ | (1,634 | ) | ||||||||||
Oil derivatives – unrealized gains (losses) | (3,564 | ) | 1,010 | (5,432 | ) | 2,502 | 2,637 | (3,564 | ) | (3,101 | ) | (5,432 | ) | |||||||||||||||||||
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Total gains (losses) on oil derivatives | $ | (4,720 | ) | $ | 1,088 | $ | (7,066 | ) | $ | 2,502 | $ | 1,673 | $ | (4,720 | ) | $ | (3,977 | ) | $ | (7,066 | ) | |||||||||||
Natural gas derivatives – realized gains (losses) | $ | 105 | $ | (56 | ) | $ | 85 | $ | (205 | ) | $ | 4 | $ | 105 | $ | (8 | ) | $ | 85 | |||||||||||||
Natural gas derivatives – unrealized gains (losses) | (249 | ) | 540 | (328 | ) | 1,852 | 156 | (249 | ) | 151 | (328 | ) | ||||||||||||||||||||
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Total gains (losses) on natural gas derivatives | $ | (144 | ) | $ | 484 | $ | (243 | ) | $ | 1,647 | $ | 160 | $ | (144 | ) | $ | 143 | $ | (243 | ) | ||||||||||||
NGL derivatives – realized (losses) | $ | (30 | ) | $ | — | $ | (27 | ) | $ | — | ||||||||||||||||||||||
NGL derivatives – realized gain (losses) | $ | 109 | $ | (30 | ) | $ | 111 | $ | (27 | ) | ||||||||||||||||||||||
NGL derivatives – unrealized gains (losses) | (323 | ) | — | (197 | ) | — | 69 | (323 | ) | 60 | (197 | ) | ||||||||||||||||||||
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Total gains (losses) on NGL derivatives | (353 | ) | — | (225 | ) | — | 178 | (353 | ) | 171 | (225 | ) | ||||||||||||||||||||
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Total gains (losses) on oil, natural gas and NGL derivatives | $ | (5,217 | ) | $ | 1,572 | $ | (7,533 | ) | $ | 4,149 | $ | 2,011 | $ | (5,217 | ) | $ | (3,663 | ) | $ | (7,533 | ) | |||||||||||
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Prices received for the six months ended June 30, 20182019 and 2017,2018, respectively, including the impact of derivatives were:
2018 | 2017 | 2019 | 2018 | |||||||||||||
Oil Price | $ | 59.26 | $ | 60.08 | $ | 54.56 | $ | 59.26 | ||||||||
Gas Price | $ | 2.17 | $ | 2.37 | $ | 1.00 | $ | 2.17 | ||||||||
NGLS Price | $ | 27.15 | $ | 26.62 | $ | 18.52 | $ | 27.15 |
Field service income increased $0.1$0.4 million or 3.3%0.01% from $4.3 million for the second quarter 2017 to $4.4 million for the second quarter 2018 and $0.6 million, or 7.4% from $8.1to $4.8 million for the six months ended June 30, 2017 tosecond quarter 2019 and $0.8 million, or 0.01% from $8.7 million for the six months ended June 30, 2018.2018 to $9.5 million for the six months ended June 30, 2019. This increase is a combined result of increased utilization and rates charged to customers during the 20182019 period. Workover rig services, hot oil treatments, salt water hauling and disposal represent the bulk of our field service operations.
Lease operating expense increased $1.6decreased $0.7 million or 22.4%0.01% from $7.2 million for the second quarter 2017 to $8.8 million for the second quarter 2018 and increased $3.0 million, or 21.1% from $14.3to $8.1 million for the six months ended June 30, 2017 tosecond quarter 2019, and decreased $1.1 million or 0.01% from $17.3 million for the six months ended June 30, 2018.2018 to $16.2 million for the six months ended June 30, 2019. This increasedecrease is primarily due to the sales of high lifting cost properties during 2019 combined with lower production taxes related to lower commodity prices, offset by costs related to new wells broughton-line and general rate increases on vendor services and increased production taxes related to increased prices and production during the first sixthree months of 20182019 as compared to the same period of 2017.2018.
Field service expense increased $0.2$0.8 million or 5.7%0.02% from $3.0 million for the second quarter 2017 to $3.2 million for the second quarter 2018 and increased $0.4 million, or 6.7% from $6.0to $4.0 million for the six months ended June 30, 2017 tosecond quarter 2019 and increased $1.2 million, or 0.02% from $6.4 million for the six months ended June 30, 2018.2018 to $7.6 million for the six months ended June 30, 2019. Field service expenses primarily consist of salaries and vehicle operating expenses which have increased during the six months ended June 30, 20182019 over the same period of 20172018 as a direct result of increased services and utilization of the equipment.
Depreciation, depletion, amortization and accretion on discounted liabilities decreased $0.1increased $1.4 million, or 1.3%0.02% from $8.0 million for the second quarter 2017 to $7.9 million for the second quarter 2018 and $0.2 million, or 1.3% from $16.0to $9.3 million for the six months ended June 30, 2017 tosecond quarter 2019 and $2.8 million, or 0.02% from $15.8 million for the six months ended June 30, 2018 to $18.6 million for the six months ended June 30, 2019, reflecting the increased reserve base and production related to new wells placed on production late in 2017.2018 and the first two quarters of 2019.
General and administrative expense increased $4.2$1.3 million, or 96%0.01% from $4.4 million for the six months ended June 30, 2017 to $8.5 million for the six months ended June 30, 2018 to $9.8 million for the six months ended June 30, 2019, and decreased $50 thousand,increased $0.3 million, or 1.9%0.01% from $2.62$2.6 million for the three months ended June 30, 20172018 to $2.57$2.9 million for the three months ended June 30, 2018.2019. This increase in 20182019 reflects the combination of a reduction in G&A reimbursements related to the decrease in gains on salessale of properties from 2017 to 2018property and increases in personnel costs.
Gain on sale and exchange of assets of $2.7 million and $41.7$1.7 million for the six months ended June 30, 2018 and June 30, 2017,2019, respectively consists of sales ofnon-essential oil and gas interests and field service equipment.
Interest expense increased from $0.5 million for the second quarter 2017 to $0.9 million for the second quarter 2018 and from $1.1to $1.0 million for the six months ended June 30, 2017 tosecond quarter 2019 and from $1.8 million for the six months ended June 30, 2018.2018 to $2.0 million for the six months ended June 30, 2019. This increase reflects the increase in current borrowings under our revolving credit agreement.
Income tax expense decreased $12.9 million due to a lower effective tax rate and lowerpre-tax income. The effective tax rates for the six months ofJune 30, 2018 and 2017 were 25.12% and 32.86%, respectively. The decrease in the effective tax rate is primarily2019 periods varied due to the impact of the Tax Cuts and Jobs Act changes that are effective January 1, 2018.change in net income for those periods.
LIQUIDITY AND CAPITAL RESOURCES
Our primary sources of liquidity are cash flows generated from operations, through our producing oil and& gas properties and field services business, and from sales ofnon-core acreage.
Net cash used inprovided by our operating activities for the six months ended June 30, 20182019 was $7.4$13.7 million compared to $14.5$7.4 million provided by operating activities for the six months ended June 30, 2017.2018. 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 vast 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 in order 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, we will be able to access sufficient additional capital through bank financing.
We currently maintain a credit facility totaling $300 million, with a borrowing base of $90 million. TheAs of August 1, 2019 the Company currently has $64$64.5 million in outstanding borrowings and $26$25.5 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 redetermined estimate of proved oil and gas reserves. The next borrowing base review is scheduled for November 2018.December 2019. 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 andand/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 redetermined 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 agreements for oil natural gas and natural gas liquids.gas.
Volumes | Prices | |||||||||||||||||||||||||||||||||||||||
2018 | 2019 | 2020 | 2018 | 2019 | 2020 | 2019 | 2020 | 2019 | 2020 | |||||||||||||||||||||||||||||||
Natural Gas (MMBTU) | 1,200,000 | 749,000 | 180,000 | $ | 2.97 | $ | 2.93 | $ | 2.95 | 180,000 | 180,000 | $ | 2.77 | $ | 2.95 | |||||||||||||||||||||||||
Natural Gas Liquids (barrels) | 36,000 | 60,000 | — | $ | 22.73 | $ | 21.66 | 30,000 | — | $ | 21.66 | — | ||||||||||||||||||||||||||||
Oil (barrels) | 143,100 | 540,500 | 100,500 | $ | 51.95 | $ | 53.53 | $ | 56.11 | 264,000 | 225,500 | $ | 53.00 | $ | 58.43 |
Maintaining a strong balance sheet and ample liquidity are key components of our business strategy. For 2018,2019, we will continue our focus on preserving financial flexibility and ample liquidity as we manage the risks facing our industry. Our 20182019 capital budget is reflective of currentdecreased 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, divestnon-strategic 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.
We have in place both a stock repurchase program and a limited partnership interest repurchase program under which we expect to continue spending during 2018. For the six month period ended June 30, 2018,2019. As of August 1, 2019, we have spent $3.7$4.109 million under these programs.programs during 2019.
Item 3. |
The Company is a smaller reporting company and no response is required pursuant to this Item.
Item 4. | CONTROLS AND PROCEDURES |
As of the end of the current reported period covered by this report, the Company carried out an evaluation, under the supervision and with the participation of the Company’s management, including the Company’s Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of the Company’s disclosure controls and procedures pursuant to Rules13a-15 and15d-15 of the Securities Exchange Act of 1934 (the “Exchange Act”). Based upon that evaluation, the Chief Executive Officer and Chief Financial Officer concluded that the Company’s disclosure controls and procedures are effective with respect to the recording, processing, summarizing and reporting, within the time periods specified in the Commission’s rules and forms, of information required to be disclosed by the Company in the reports that it files or submits under the Exchange Act.
There were no changes in the Company’s internal control over financial reporting that occurred during the first six months of 20182019 that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.
Item 1. |
None.
Item 1A. |
The Company is a smaller reporting company and no response is required pursuant to this Item.
Item 2. | UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS |
There were no sales of equity securities by the Company during the period covered by this report.
During the six months ended June 30, 2018,2019, the Company purchased the following shares of common stock as treasury shares.
2018 Month | Number of Shares | Average Price Paid per share | Maximum Number of Shares that May Yet Be Purchased Under The Program at Month - End (1) | |||||||||||||||||||||
2019 Month | Number of Shares | Average Price Paid per share | Maximum Number of Shares that May Yet Be Purchased Under The Program at Month - End (1) | |||||||||||||||||||||
January | 178 | $ | 55.55 | 122,736 | 1,386 | $ | 80.50 | 192,077 | ||||||||||||||||
February | 64,841 | $ | 50.18 | 57,895 | 2,716 | $ | 122.36 | 189,361 | ||||||||||||||||
March | 2,199 | $ | 52.50 | 55,696 | 1,861 | $ | 156.23 | 187,500 | ||||||||||||||||
April | 4,787 | $ | 54.08 | 50,909 | 2,601 | $ | 142.71 | 184,899 | ||||||||||||||||
May | 417 | $ | 69.81 | 50,492 | 10,637 | $ | 138.44 | 174,262 | ||||||||||||||||
June | 417 | $ | 69.35 | 250,075 | 3,210 | $ | 135.04 | 171,052 | ||||||||||||||||
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Total/Average | 72,839 | $ | 50.74 | 22,411 | $ | 134.40 | ||||||||||||||||||
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(1) | In December 1993, we announced that the Board of Directors authorized a stock repurchase program whereby we may purchase outstanding shares of the common stock fromtime-to-time, in open market transactions or negotiated sales. On October 31, 2012 |
Item 6. |
The following exhibits are filed as a part of this report:
Pursuant to the requirements of the Securities and Exchange Act of 1934, Registrant has duly caused this Report to be signed on its behalf by the undersigned thereunto duly authorized.
PrimeEnergy Resources Corporation | ||||||
(Registrant) | ||||||
August | /s/ Charles E. Drimal, Jr. | |||||
(Date) | Charles E. Drimal, Jr. | |||||
President | ||||||
Principal Executive Officer | ||||||
August | 14, 2019 | /s/ Beverly A. Cummings | ||||
(Date) | Beverly A. Cummings | |||||
Executive Vice President | ||||||
Principal Financial Officer |
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