UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q/A10-Q
Amendment No. 2
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| ☒ | QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the quarterly period ended SeptemberJune 30, 20192020
OR
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| ☐ | TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the transition period from to
Commission file number 001-37907
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| EXTRACTION OIL & GAS, INC. | |
| (Exact name of registrant as specified in its charter) | |
| | | | | | | | | | | |
| Delaware | | | 46-1473923 |
(State or other jurisdiction of
incorporation or organization) | | | (IRS Employer
Identification No.) |
| | | |
| 370 17th Street | | | |
| Suite 5300 | | | |
| Denver, | Colorado | | 80202 |
| (Address of principal executive offices) | | | |
(720) 557-8300
| | | | | |
| (Registrant’s telephone number, including area code) | |
| | | | | | | | | | | | | | |
Securities registered pursuant to Section 12(b) of the Act: | | | | |
| | | | |
Title of each class | | Trading Symbol(s) | | Name of exchange on which registered |
Common Stock, par value $0.01 | | XOG | | NASDAQ Global Select Market |
Securities registered pursuant to Section 12(b) of the Act: None.
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 filing requirements for the past 90 days. Yes ☒ No ☐
Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). Yes ☒ No ☐
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a 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 Rule 12b-2 of the Exchange Act.
| | | | | | | | | | | | | | |
Large accelerated filerAccelerated Filer | | ☒☐ | Accelerated filerFiler | ☐☒ |
Non-accelerated filerNon-Accelerated Filer | | ☐ | Smaller reporting companyReporting Company | ☐☒ |
| | | Emerging growth companyGrowth 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 Rule 12b-2 of the Exchange Act). Yes ☐ No ☒
The total number of shares of common stock, par value $0.01 per share, outstanding as of December 20, 2019August 7, 2020 was 138,657,726.138,343,932.
EXPLANATORY NOTE
This Amendment No. 2 to the Quarterly Report on Form 10Q/A (this “Amendment”) is being filed by Extraction Oil & Gas, Inc. (the “Company”) to amend the Company’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2019, which was originally filed with the Securities and Exchange Commission (the “SEC”) on November 7, 2019 (the “Original Filing”) and further amended and filed on November 8, 2019 (“Amendment No. 1”).
On December 17, 2019, the Company’s management concluded, and the audit committee concurred, that the Company’s previously issued Amendment No. 1 condensed consolidated financial statements should no longer be relied upon. This conclusion was reached due to an accounting error relating to the improper identification of the contract term for one of the Company’s revenue contracts that included an automatic renewal provision. The contract term impacts the amount of consideration that can be included in the transaction price. The Company had accounted for revenue relating to the contract assuming a term ending in August 2023. Upon subsequent review, the Company determined that the proper accounting treatment pursuant to ASC 606 - Revenue from Contracts with Customers would have been to evaluate the contract with a term ending on April 30, 2021 because the contract may be terminated by either party with no penalty effective as of such date. However, the contract cannot be extended beyond October 2026. Accounting for the contract with an earlier termination date results in a decrease to the Company’s revenues, net income and adjustments to the Company’s assets and liabilities as reported in Amendment No. 1.
This amendment is being filed solely to (i) restate the condensed consolidated financial statements for the accounting error described above to the condensed consolidated financial statements (and make corresponding changes to Risk Factors and the Management’s Discussion and Analysis of Financial Condition and Results of Operations sections in this Amendment) and (ii) amend Item 4 (Controls and Procedures).
The following sections in the Original Filing and in Amendment No. 1 are revised in this Form 10-Q/A to reflect the restatement:
•Part I - Item 1 - Condensed Consolidated Financial Statements (Unaudited)
•Part I - Item 2 - Management’s Discussion and Analysis of Financial Condition and Results of Operations
•Part I - Item 4 - Controls and Procedures
•Part II - Item 1A - Risk Factors
•Part II - Item 6 - Exhibits
Our principal executive officer and principal financial officer have also provided new certifications as required by Sections 302 and 906 of the Sarbanes-Oxley Act of 2002. The certifications are included in this Form 10-Q/A as Exhibits 31.1, 31.2, 32.1 and 32.2. For the convenience of the reader, this Form 10-Q/A sets forth the information in the Original Filing in its entirety, as such information, as well as the information in Amendment No. 1, are modified and superseded where necessary to reflect the restatement. Except as provided above, this Amendment No. 2 does not reflect events occurring after the filing of the Original Filing and does not amend or otherwise update any information in the Original Filing. Accordingly, this Form 10-Q/A should be read in conjunction with our filings with the SEC subsequent to the date on which we filed the Original Filing with the SEC.
EXTRACTION OIL & GAS, INC.
TABLE OF CONTENTS
GLOSSARY OF OIL AND GAS TERMS
Unless indicated otherwise or the context otherwise requires, references in this Quarterly Report on Form 10-Q (“Quarterly Report”) to the "Company," “Extraction,” "us," "we," "our," or "ours" or like terms refer to Extraction Oil & Gas, Inc., together with its consolidated subsidiaries. When the context requires, we refer to these entities separately.
The terms defined in this section are used throughout this Quarterly Report:
"Bbl" means one stock tank barrel, or 42 U.S. gallons liquid volume, used in reference to oil or other liquid hydrocarbons.
"Bbl/d" means Bbl per day.
"Btu" means one British thermal unit – a measure of the amount of energy required to raise the temperature of a one-pound mass of water one degree Fahrenheit at sea level.
"BOE" means barrels of oil equivalent. Oil equivalents are determined using the ratio of six Mcf of gas (including gas liquids) to one Bbl of oil.
"BOE/d" means BOE per day.
"CIG" means Colorado Interstate Gas, which is calculated as NYMEX Henry Hub index price less the Rocky Mountains (CIGC) Inside FERC fixed price.
"Completion" means the installation of permanent equipment for the production of oil or natural gas.
“Dekatherms” means a unit of energy used primarily to measure natural gas equal to 1,000,000 Btus (MMBtu).
"Field" means an area consisting of a single reservoir or multiple reservoirs all grouped on or related to the same individual geological structural feature or stratigraphic condition.
"Fracturing" or "hydraulic fracturing" means a procedure to stimulate production by forcing a mixture of fluid and proppant (usually sand) into the formation under high pressure. This creates artificial fractures in the reservoir rock, which increases permeability and porosity.
"Gas" or "Natural gas" means the lighter hydrocarbons and associated non-hydrocarbon substances occurring naturally in an underground reservoir, which under atmospheric conditions are essentially gases but which may contain liquids.
"Gross Acres" or "Gross Wells" means the total acres or wells, as the case may be, in which we have a working interest.
"Henry Hub" meansHenry Hub index. Natural gas distribution point where prices are set for natural gas futures contracts traded on the NYMEX.
"Horizontal drilling" or "horizontal well" means a wellbore that is drilled laterally.
"Leases" means full or partial interests in oil or gas properties authorizing the owner of the lease to drill for, produce and sell oil and natural gas in exchange for any or all of rental, bonus and royalty payments. Leases are generally acquired from private landowners (fee leases) and from federal and state governments on acreage held by them.
"MBbl" One thousand barrels of oil, condensate or NGL.
"MBoe" One thousand barrels of oil equivalent. Oil equivalents are determined using the ratio of six Mcf of gas (including gas liquids) to one Bbl of oil.
"Mcf" is an abbreviation for "1,000 cubic feet," which is a unit of measurement of volume for natural gas.
"MMBtu" One million Btus.
"MMcf" is an abbreviation for "1,000,000 cubic feet," which is a unit of measurement of volume for natural gas.
"Net Acres" or "Net Wells" is the sum of the fractional working interests owned in gross acres or wells, as the case may be, expressed as whole numbers and fractions thereof.
"NGL" means natural gas liquids.
"NYMEX" means New York Mercantile Exchange.
"Proved reserves" means those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs, and under existing economic conditions, operating methods and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.
"Reasonable certainty" means a high degree of confidence that the reserves quantities will be recovered, when a deterministic method is used. A high degree of confidence exists if the reserves quantity is much more likely to be achieved than not, and, as changes due to increased availability of geoscience (geological, geophysical and geochemical), engineering and economic data are made to estimated ultimate recovery (“EUR”) with time, reasonably certain EUR is much more likely to increase or remain constant than to decrease.
"Reservoir" means a porous and permeable underground formation containing a natural accumulation of producible natural gas and/or oil that is confined by impermeable rock or water barriers and is individual and separate from other reservoirs.
"Royalty" means the share paid to the owner of mineral rights, expressed as a percentage of gross income from oil and natural gas produced and sold unencumbered by expenses relating to the drilling, completing and operating of the affected well.
"SEC" means the Securities and Exchange Commission.
"Undeveloped leasehold acreage" means the leased acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and natural gas, regardless of whether such acreage contains estimated net proved reserves.
"Wattenberg Field" means the Greater Wattenberg Area within the Denver-Julesburg Basin of Colorado as defined by the Colorado Oil and Gas Conservation Commission, which are the lands from and including Townships 2 South to 7 North and Ranges 61 West to 69 West, Six Principal Median.
"Working interest" means an interest in an oil and natural gas lease entitling the holder at its expense to conduct drilling and production operations on the leased property and to receive the net revenues attributable to such interest, after deducting the landowner's royalty, any overriding royalties, production costs, taxes and other costs.
"WTI" means the price of West Texas Intermediate oil on the NYMEX.
PART I. FINANCIAL INFORMATION
ITEM 1. CONSOLIDATED FINANCIAL STATEMENTS
EXTRACTION OIL & GAS, INC.
CONDENSED CONSOLIDATED BALANCE SHEETS
(In thousands, except share data)
(Debtor-In-Possession)
(Unaudited)
| | | September 30,
2019 | | December 31,
2018 | | | | | | | | | | |
| | As restated | | | | June 30,
2020 | | December 31,
2019 |
| ASSETS | ASSETS | | | ASSETS | | | |
| Current Assets: | Current Assets: | | Current Assets: | |
| Cash and cash equivalents | Cash and cash equivalents | $ | 57,728 | | | $ | 234,986 | | Cash and cash equivalents | $ | 62,553 | | | $ | 32,382 | |
| Accounts receivable | | |
| Accounts receivable, net | | Accounts receivable, net | |
| Trade | Trade | 55,095 | | | 41,695 | | Trade | 48,599 | | | 32,009 | |
| Oil, natural gas and NGL sales | Oil, natural gas and NGL sales | 69,750 | | | 91,225 | | Oil, natural gas and NGL sales | 48,275 | | | 105,103 | |
| Inventory, prepaid expenses and other | Inventory, prepaid expenses and other | 28,854 | | | 26,816 | | Inventory, prepaid expenses and other | 34,732 | | | 36,702 | |
| Commodity derivative asset | Commodity derivative asset | 66,480 | | | 48,907 | | Commodity derivative asset | 55,667 | | | 17,554 | |
| Assets held for sale | — | | | 21,008 | | |
| Total Current Assets | Total Current Assets | 277,907 | | | 464,637 | | Total Current Assets | 249,826 | | | 223,750 | |
| Property and Equipment (successful efforts method), at cost: | Property and Equipment (successful efforts method), at cost: | | | | Property and Equipment (successful efforts method), at cost: | | | |
| Proved oil and gas properties | Proved oil and gas properties | 4,494,226 | | | 3,916,622 | | Proved oil and gas properties | 4,707,989 | | | 4,530,934 | |
| Unproved oil and gas properties | Unproved oil and gas properties | 572,400 | | | 609,284 | | Unproved oil and gas properties | 356,741 | | | 524,214 | |
| Wells in progress | Wells in progress | 104,429 | | | 144,323 | | Wells in progress | 137,944 | | | 149,733 | |
| Less: accumulated depletion, depreciation and amortization | (1,498,608) | | | (1,152,590) | | |
| Less: accumulated depletion, depreciation, amortization and impairment charges | | Less: accumulated depletion, depreciation, amortization and impairment charges | (3,135,748) | | | (2,985,983) | |
| Net oil and gas properties | Net oil and gas properties | 3,672,447 | | | 3,517,639 | | Net oil and gas properties | 2,066,926 | | | 2,218,898 | |
| Gathering systems and facilities | 307,038 | | | 114,469 | | |
| Gathering systems and facilities, net of accumulated depreciation | | Gathering systems and facilities, net of accumulated depreciation | — | | | 315,777 | |
| Other property and equipment, net of accumulated depreciation | Other property and equipment, net of accumulated depreciation | 73,265 | | | 39,849 | | Other property and equipment, net of accumulated depreciation | 71,912 | | | 72,542 | |
| Net Property and Equipment | Net Property and Equipment | 4,052,750 | | | 3,671,957 | | Net Property and Equipment | 2,138,838 | | | 2,607,217 | |
| Non-Current Assets: | Non-Current Assets: | | | | Non-Current Assets: | | | |
| Commodity derivative asset | Commodity derivative asset | 41,520 | | | 8,432 | | Commodity derivative asset | — | | | 13,229 | |
| Other non-current assets | Other non-current assets | 69,290 | | | 21,001 | | Other non-current assets | 15,692 | | | 82,761 | |
| Total Non-Current Assets | Total Non-Current Assets | 110,810 | | | 29,433 | | Total Non-Current Assets | 15,692 | | | 95,990 | |
| Total Assets | Total Assets | $ | 4,441,467 | | | $ | 4,166,027 | | Total Assets | $ | 2,404,356 | | | $ | 2,926,957 | |
| LIABILITIES AND STOCKHOLDERS' EQUITY | LIABILITIES AND STOCKHOLDERS' EQUITY | | | | LIABILITIES AND STOCKHOLDERS' EQUITY | | | |
| Current Liabilities: | Current Liabilities: | | Current Liabilities: | |
| Accounts payable and accrued liabilities | Accounts payable and accrued liabilities | $ | 216,194 | | | $ | 186,218 | | Accounts payable and accrued liabilities | $ | 43,329 | | | $ | 190,864 | |
| Revenue payable | Revenue payable | 96,140 | | | 117,344 | | Revenue payable | 5,030 | | | 108,493 | |
| Production taxes payable | Production taxes payable | 114,969 | | | 57,516 | | Production taxes payable | — | | | 115,489 | |
| Commodity derivative liability | Commodity derivative liability | 108 | | | 196 | | Commodity derivative liability | — | | | 1,998 | |
| Accrued interest payable | Accrued interest payable | 17,272 | | | 22,249 | | Accrued interest payable | 4,145 | | | 20,625 | |
| Asset retirement obligations | Asset retirement obligations | 26,426 | | | 15,729 | | Asset retirement obligations | — | | | 27,058 | |
| Liabilities related to assets held for sale | — | | | 3,146 | | |
| DIP Credit Facility—Note 6 | | DIP Credit Facility—Note 6 | 37,500 | | | — | |
| Credit Facility—Note 6 | | Credit Facility—Note 6 | 481,935 | | | — | |
| Total Current Liabilities | Total Current Liabilities | 471,109 | | | 402,398 | | Total Current Liabilities | 571,939 | | | 464,527 | |
| Non-Current Liabilities: | Non-Current Liabilities: | | | | Non-Current Liabilities: | | | |
| Credit facility | 550,000 | | | 285,000 | | |
| Credit Facility | | Credit Facility | — | | | 470,000 | |
| Senior Notes, net of unamortized debt issuance costs | Senior Notes, net of unamortized debt issuance costs | 1,085,217 | | | 1,132,659 | | Senior Notes, net of unamortized debt issuance costs | — | | | 1,085,777 | |
| Production taxes payable | Production taxes payable | 70,560 | | | 115,607 | | Production taxes payable | 1,681 | | | 98,740 | |
| Commodity derivative liability | Commodity derivative liability | 83 | | | — | | Commodity derivative liability | — | | | 108 | |
| Other non-current liabilities | Other non-current liabilities | 55,752 | | | 8,072 | | Other non-current liabilities | — | | | 54,579 | |
| Asset retirement obligations | Asset retirement obligations | 67,500 | | | 54,062 | | Asset retirement obligations | — | | | 68,850 | |
| Deferred tax liability | 110,076 | | | 109,176 | | |
| | Total Non-Current Liabilities | Total Non-Current Liabilities | 1,939,188 | | | 1,704,576 | | Total Non-Current Liabilities | 1,681 | | | 1,778,054 | |
| Liabilities Subject to Compromise | | Liabilities Subject to Compromise | 1,697,341 | | | — | |
| Total Liabilities | Total Liabilities | 2,410,297 | | | 2,106,974 | | Total Liabilities | 2,270,961 | | | 2,242,581 | |
| Commitments and Contingencies—Note 11 | | | | |
| Series A Convertible Preferred Stock, $0.01 par value; 50,000,000 shares authorized; 185,280 issued and outstanding | 169,282 | | | 164,367 | | |
| Stockholders' Equity: | | |
| Common stock, $0.01 par value; 900,000,000 shares authorized; 138,073,124 and 171,666,485 issued and outstanding | 1,336 | | | 1,678 | | |
| Treasury stock, at cost, 38,859,078 and 4,543,262 shares | (170,138) | | | (32,737) | | |
| Commitments and Contingencies—Note 14 | | Commitments and Contingencies—Note 14 | | | |
| Series A Convertible Preferred Stock, $0.01 par value; 50,000,000 shares authorized, 185,280 issued and outstanding | | Series A Convertible Preferred Stock, $0.01 par value; 50,000,000 shares authorized, 185,280 issued and outstanding | 187,975 | | | 175,639 | |
| Stockholders' Equity (Deficit): | | Stockholders' Equity (Deficit): | |
| Common stock, $0.01 par value; 900,000,000 share authorized; 138,343,432 and 137,657,922 issued and outstanding, respectively | | Common stock, $0.01 par value; 900,000,000 share authorized; 138,343,432 and 137,657,922 issued and outstanding, respectively | 1,336 | | | 1,336 | |
| Treasury stock, at cost, 38,859,078 shares | | Treasury stock, at cost, 38,859,078 shares | (170,138) | | | (170,138) | |
| Additional paid-in capital | Additional paid-in capital | 2,164,921 | | | 2,153,661 | | Additional paid-in capital | 2,140,327 | | | 2,156,383 | |
| Accumulated deficit | Accumulated deficit | (392,452) | | | (375,788) | | Accumulated deficit | (2,026,105) | | | (1,743,208) | |
| Total Extraction Oil & Gas, Inc. Stockholders' Equity | 1,603,667 | | | 1,746,814 | | |
| Total Extraction Oil & Gas, Inc. Stockholders' Equity (Deficit) | | Total Extraction Oil & Gas, Inc. Stockholders' Equity (Deficit) | (54,580) | | | 244,373 | |
| Noncontrolling interest | Noncontrolling interest | 258,221 | | | 147,872 | | Noncontrolling interest | — | | | 264,364 | |
| Total Stockholders' Equity | 1,861,888 | | | 1,894,686 | | |
| Total Liabilities and Stockholders' Equity | $ | 4,441,467 | | | $ | 4,166,027 | | |
| Total Stockholders' Equity (Deficit) | | Total Stockholders' Equity (Deficit) | (54,580) | | | 508,737 | |
| Total Liabilities and Stockholders' Equity (Deficit) | | Total Liabilities and Stockholders' Equity (Deficit) | $ | 2,404,356 | | | $ | 2,926,957 | |
|
THE ACCOMPANYING NOTES ARE AN INTEGRAL PART OF
THESE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
EXTRACTION OIL & GAS, INC.
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
(In thousands, except per share data)
(Debtor-In-Possession)
(Unaudited)
| | | For the Three Months Ended September 30, | | | For the Nine Months Ended September 30, | | | | | | | | | | | | | | | | | | | | | | | |
| | 2019 | | 2018 | | 2019 | | 2018 | | For the Three Months Ended June 30, | | | For the Six Months Ended June 30, | |
| | As restated | | | | As restated | | | | 2020 | | 2019 | | 2020 | | 2019 |
| Revenues: | Revenues: | | Revenues: | | | | | | | |
| Oil sales | Oil sales | $ | 151,042 | | | $ | 225,467 | | | $ | 501,591 | | | $ | 619,211 | | Oil sales | $ | 36,290 | | | $ | 185,125 | | | $ | 160,509 | | | $ | 350,549 | |
| Natural gas sales | Natural gas sales | 16,801 | | | 23,103 | | | 74,385 | | | 66,991 | | Natural gas sales | 16,019 | | | 21,692 | | | 38,321 | | | 57,584 | |
| NGL sales | NGL sales | 9,099 | | | 33,590 | | | 44,940 | | | 86,369 | | NGL sales | 10,820 | | | 15,240 | | | 28,013 | | | 35,841 | |
| Gathering and compression | | Gathering and compression | — | | | — | | | 1,473 | | | — | |
| Total Revenues | Total Revenues | 176,942 | | | 282,160 | | | 620,916 | | | 772,571 | | Total Revenues | 63,129 | | | 222,057 | | | 228,316 | | | 443,974 | |
| Operating Expenses: | Operating Expenses: | | | | | | | | Operating Expenses: | | | | | | | |
| Lease operating expenses | 22,979 | | | 20,283 | | | 68,445 | | | 61,760 | | |
| Lease operating expense | | Lease operating expense | 22,984 | | | 23,608 | | | 53,374 | | | 45,465 | |
| Midstream operating expenses | | Midstream operating expenses | — | | | — | | | 3,935 | | | — | |
| Transportation and gathering | Transportation and gathering | 6,922 | | | 11,786 | | | 29,142 | | | 29,284 | | Transportation and gathering | 26,306 | | | 11,854 | | | 49,092 | | | 22,219 | |
| Production taxes | Production taxes | 9,711 | | | 21,605 | | | 46,419 | | | 66,317 | | Production taxes | 4,679 | | | 18,580 | | | 18,133 | | | 36,709 | |
| Exploration expenses | 13,245 | | | 11,038 | | | 32,725 | | | 21,326 | | |
| Exploration and abandonment expenses | | Exploration and abandonment expenses | 62,661 | | | 13,287 | | | 175,141 | | | 19,481 | |
| Depletion, depreciation, amortization and accretion | Depletion, depreciation, amortization and accretion | 114,996 | | | 107,315 | | | 352,134 | | | 310,296 | | Depletion, depreciation, amortization and accretion | 82,620 | | | 118,368 | | | 158,670 | | | 237,138 | |
| Impairment of long lived assets | Impairment of long lived assets | — | | | 16,166 | | | 11,233 | | | 16,294 | | Impairment of long lived assets | 960 | | | 2,985 | | | 1,736 | | | 11,233 | |
| Gain on sale of property and equipment and assets of unconsolidated subsidiary | (1,011) | | | (83,559) | | | (1,329) | | | (143,461) | | |
| General and administrative expenses | 27,445 | | | 35,365 | | | 85,835 | | | 100,565 | | |
| Gain on sale of property and equipment | | Gain on sale of property and equipment | — | | | (97) | | | — | | | (319) | |
| General and administrative expense | | General and administrative expense | 25,148 | | | 30,740 | | | 35,744 | | | 58,392 | |
| Other operating expenses | | Other operating expenses | 13,209 | | | — | | | 65,784 | | | — | |
| Total Operating Expenses | Total Operating Expenses | 194,287 | | | 139,999 | | | 624,604 | | | 462,381 | | Total Operating Expenses | 238,567 | | | 219,325 | | | 561,609 | | | 430,318 | |
| Operating Income (Loss) | Operating Income (Loss) | (17,345) | | | 142,161 | | | (3,688) | | | 310,190 | | Operating Income (Loss) | (175,438) | | | 2,732 | | | (333,293) | | | 13,656 | |
| Other Income (Expense): | Other Income (Expense): | | | | | | | | Other Income (Expense): | | | | | | | |
| Commodity derivatives gain (loss) | 87,956 | | | (35,913) | | | 39,383 | | | (175,752) | | |
| Interest expense | (23,224) | | | (20,725) | | | (54,791) | | | (103,229) | | |
| Commodity derivative gain (loss) | | Commodity derivative gain (loss) | (69,301) | | | 73,519 | | | 193,714 | | | (48,572) | |
| Loss on deconsolidation of Elevation Midstream, LLC | | Loss on deconsolidation of Elevation Midstream, LLC | — | | | — | | | (73,139) | | | — | |
| Reorganization items, net | | Reorganization items, net | (26,919) | | | — | | | (26,919) | | | — | |
| Interest expense(1) | | Interest expense(1) | (20,314) | | | (18,558) | | | (41,672) | | | (31,566) | |
| Other income | Other income | 1,337 | | | 1,827 | | | 3,332 | | | 3,094 | | Other income | 38 | | | 851 | | | 612 | | | 1,994 | |
| Total Other Income (Expense) | Total Other Income (Expense) | 66,069 | | | (54,811) | | | (12,076) | | | (275,887) | | Total Other Income (Expense) | (116,496) | | | 55,812 | | | 52,596 | | | (78,144) | |
| Income (Loss) Before Income Taxes | Income (Loss) Before Income Taxes | 48,724 | | | 87,350 | | | (15,764) | | | 34,303 | | Income (Loss) Before Income Taxes | (291,934) | | | 58,544 | | | (280,697) | | | (64,488) | |
| Income tax expense | (14,800) | | | (22,200) | | | (900) | | | (12,300) | | |
| Income tax (expense) benefit | | Income tax (expense) benefit | — | | | (15,100) | | | (2,200) | | | 13,900 | |
| Net Income (Loss) | Net Income (Loss) | $ | 33,924 | | | $ | 65,150 | | | $ | (16,664) | | | $ | 22,003 | | Net Income (Loss) | $ | (291,934) | | | $ | 43,444 | | | $ | (282,897) | | | $ | (50,588) | |
| Net income attributable to noncontrolling interest | Net income attributable to noncontrolling interest | 5,776 | | | 3,305 | | | 13,849 | | | 3,305 | | Net income attributable to noncontrolling interest | — | | | 4,097 | | | 6,160 | | | 8,072 | |
| Net Income (Loss) Attributable to Extraction Oil & Gas, Inc. | Net Income (Loss) Attributable to Extraction Oil & Gas, Inc. | 28,148 | | | 61,845 | | | (30,513) | | | 18,698 | | Net Income (Loss) Attributable to Extraction Oil & Gas, Inc. | (291,934) | | | 39,347 | | | (289,057) | | | (58,660) | |
| Adjustments to reflect Series A Preferred Stock dividends and accretion of discount | Adjustments to reflect Series A Preferred Stock dividends and accretion of discount | (4,403) | | | (4,236) | | | (13,079) | | | (12,593) | | Adjustments to reflect Series A Preferred Stock dividends and accretion of discount | (5,818) | | | (4,359) | | | (12,336) | | | (8,676) | |
| Net Income (Loss) Attributable to Common Shareholders | 23,745 | | | 57,609 | | | (43,592) | | | 6,105 | | |
| Income (Loss) Per Common Share (Note 10) | | | | | | | | |
| Net Income (Loss) Available to Common Shareholders, Basic and Diluted | | Net Income (Loss) Available to Common Shareholders, Basic and Diluted | (297,752) | | | 34,988 | | | $ | (301,393) | | | $ | (67,336) | |
| Income (Loss) Per Common Share (Note 13) | | Income (Loss) Per Common Share (Note 13) | | | | | | | |
| Basic and diluted | Basic and diluted | $ | 0.17 | | | $ | 0.33 | | | $ | (0.28) | | | $ | 0.03 | | Basic and diluted | $ | (2.16) | | | $ | 0.22 | | | $ | (2.18) | | | $ | (0.41) | |
| Weighted Average Common Shares Outstanding | Weighted Average Common Shares Outstanding | | | | | | | | Weighted Average Common Shares Outstanding | | | | | | | |
| Basic and diluted | Basic and diluted | 137,789 | | | 175,814 | | | 155,847 | | | 175,269 | | Basic and diluted | 138,163 | | | 159,410 | | | 137,945 | | | 165,025 | |
THE ACCOMPANYING NOTES ARE AN INTEGRAL PART OF
THESE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
EXTRACTION OIL & GAS, INC.
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(Debtor-In-Possession)
(In thousands)
(Unaudited)
| | | | | | | | | | | |
| For the Six Months Ended June 30, | | |
| 2020 | | 2019 |
| Cash flows from operating activities: | | | |
| Net loss | $ | (282,897) | | | $ | (50,588) | |
| Reconciliation of net loss to net cash provided by operating activities: | | | |
| Depletion, depreciation, amortization and accretion | 158,670 | | | 237,138 | |
| Abandonment and impairment of unproved properties | 169,559 | | | 14,993 | |
| Impairment of long lived assets | 1,736 | | | 11,233 | |
| Gain on sale of property and equipment | — | | | (319) | |
| Gain on repurchase of 2026 Senior Notes | — | | | (10,486) | |
| Amortization of debt issuance costs | 3,190 | | | 2,826 | |
| Non-cash lease expense | 8,986 | | | 5,058 | |
| Non-cash reorganization items, net | 13,270 | | | — | |
| Contract asset | 12,317 | | | — | |
| Commodity derivatives (gain) loss | (193,714) | | | 48,572 | |
| Settlements on commodity derivatives | 65,447 | | | (21,918) | |
| Premiums paid on commodity derivatives | — | | | (2,852) | |
| Earnings in unconsolidated subsidiaries | (480) | | | (576) | |
| Loss on deconsolidation of Elevation Midstream, LLC | 73,139 | | | — | |
| Distributions from unconsolidated subsidiaries | — | | | 1,990 | |
| Deferred income tax expense (benefit) | 2,200 | | | (13,900) | |
| Stock-based compensation | 2,560 | | | 27,945 | |
| Changes in current assets and liabilities: | | | |
| Accounts receivable—trade | (16,998) | | | 4,163 | |
| Accounts receivable—oil, natural gas and NGL sales | 56,828 | | | 5,201 | |
| Inventory, prepaid expenses and other | (12,289) | | | 600 | |
| Accounts payable and accrued liabilities | 64,981 | | | (2,973) | |
| Revenue payable | (18,924) | | | (23,553) | |
| Production taxes payable | (23,019) | | | (3,461) | |
| Accrued interest payable | 15,565 | | | (2,602) | |
| Asset retirement expenditures | (16,173) | | | (8,047) | |
| Net cash provided by operating activities | 83,954 | | | 218,444 | |
| Cash flows from investing activities: | | | |
| Oil and gas property additions | (193,334) | | | (314,975) | |
| Sale of property and equipment | 11,147 | | | 19,982 | |
| Gathering systems and facilities additions, net of cost reimbursements | 4,193 | | | (115,337) | |
| Other property and equipment additions | (3,386) | | | (25,161) | |
| Investment in unconsolidated subsidiaries | (10,033) | | | (14,962) | |
| Distributions from unconsolidated subsidiary, return of capital | — | | | 1,209 | |
| Net cash used in investing activities | (191,413) | | | (449,244) | |
| Cash flows from financing activities: | | | |
| Borrowings under Credit Facility | 200,500 | | | 245,000 | |
| Repayments under Credit Facility | (70,000) | | | (50,000) | |
| Borrowings under DIP Credit Facility | 15,000 | | | — | |
| Repurchase of 2026 Senior Notes | — | | | (39,325) | |
| Repurchase of common stock | — | | | (116,496) | |
| Payment of employee payroll withholding taxes | (120) | | | (582) | |
| Dividends on Series A Preferred Stock | — | | | (5,443) | |
| Debt issuance costs and other financing fees | (22) | | | (1,433) | |
| | | |
| Net cash provided by financing activities | 145,358 | | | 31,721 | |
| Effect of deconsolidation of Elevation Midstream, LLC | (7,728) | | | — | |
| Increase (decrease) in cash and cash equivalents | 30,171 | | | (199,079) | |
| Cash, cash equivalents at beginning of period | 32,382 | | | 234,986 | |
| Cash, cash equivalents at end of the period | $ | 62,553 | | | $ | 35,907 | |
| Supplemental cash flow information: | | | |
| Property and equipment included in accounts payable and accrued liabilities | $ | 64,751 | | | $ | 223,527 | |
| Cash paid for interest | $ | 26,955 | | | $ | 45,648 | |
| Cash paid for reorganization items, net | $ | 3,787 | | | $ | — | |
| Accretion of beneficial conversion feature of Series A Preferred Stock | $ | 3,587 | | | $ | 3,233 | |
| Preferred Units commitment fees and dividends paid-in-kind | $ | 6,160 | | | $ | 8,073 | |
| Series A Preferred Stock dividends paid-in-kind | $ | 8,749 | | | $ | — | |
| Derivative unwinds reducing the Credit Facility | $ | 96,065 | | | $ | — | |
THE ACCOMPANYING NOTES ARE AN INTEGRAL PART OF
THESE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
EXTRACTION OIL & GAS, INC.
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN
STOCKHOLDERS’ EQUITY AND NONCONTROLLING INTEREST
(Debtor-In-Possession)
(In thousands)
(Unaudited)
As restated
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Common Stock | | | | | Treasury Stock | | | | | Additional Paid in Capital | | | Accumulated Deficit | | | Extraction Oil & Gas, Inc. Stockholders' Equity | | | Noncontrolling interest | | | Total Stockholders' Equity | |
| Shares | | | Amount | | | Shares | | | Amount | | | | | | | | | Amount | | | |
| Balance at January 1, 2019 | 176,210 | | | $ | 1,678 | | | 4,543 | | | $ | (32,737) | | | $ | 2,153,661 | | | $ | (375,788) | | | $ | 1,746,814 | | | $ | 147,872 | | | $ | 1,894,686 | |
| | | | | | | | | | | | | | | | | |
| Preferred Units issuance costs | — | | | — | | | — | | | — | | | — | | | — | | | — | | | (10) | | | (10) | |
| Preferred Units commitment fees & dividends paid-in-kind | — | | | — | | | — | | | — | | | (3,975) | | | — | | | (3,975) | | | 3,975 | | | — | |
| Stock-based compensation | — | | | — | | | — | | | — | | | 13,008 | | | — | | | 13,008 | | | — | | | 13,008 | |
| Series A Preferred Stock dividends | — | | | — | | | — | | | — | | | (2,721) | | | — | | | (2,721) | | | — | | | (2,721) | |
| Accretion of beneficial conversion feature on Series A Preferred Stock | — | | | — | | | — | | | — | | | (1,596) | | | — | | | (1,596) | | | — | | | (1,596) | |
| Repurchase of common stock | — | | | (77) | | | 7,824 | | | (32,135) | | | — | | | — | | | (32,212) | | | — | | | (32,212) | |
| Restricted stock issued, including payment of tax withholdings using withheld shares | 270 | | | — | | | — | | | — | | | (454) | | | — | | | (454) | | | — | | | (454) | |
| Net loss | — | | | — | | | — | | | — | | | — | | | (94,032) | | | (94,032) | | | — | | | (94,032) | |
| Balance at March 31, 2019 | 176,480 | | | $ | 1,601 | | | 12,367 | | | $ | (64,872) | | | $ | 2,157,923 | | | $ | (469,820) | | | $ | 1,624,832 | | | $ | 151,837 | | | $ | 1,776,669 | |
| | | | | | | | | | | | | | | | | |
| Preferred Units issuance costs | — | | | — | | | — | | | — | | | — | | | — | | | — | | | 10 | | | 10 | |
| Preferred Units commitment fees & dividends paid-in-kind | — | | | — | | | — | | | — | | | (4,098) | | | — | | | (4,098) | | | 4,098 | | | — | |
| Stock-based compensation | — | | | — | | | — | | | — | | | 14,957 | | | — | | | 14,957 | | | — | | | 14,957 | |
| Series A Preferred Stock dividends | — | | | — | | | — | | | — | | | (2,722) | | | — | | | (2,722) | | | — | | | (2,722) | |
| Accretion of beneficial conversion feature on Series A Preferred Stock | — | | | — | | | — | | | — | | | (1,637) | | | — | | | (1,637) | | | — | | | (1,637) | |
| Repurchase of common stock | — | | | (217) | | | 21,685 | | | (84,067) | | | — | | | — | | | (84,284) | | | — | | | (84,284) | |
| Restricted stock issued, including payment of tax withholdings using withheld shares | 108 | | | — | | | — | | | — | | | (128) | | | — | | | (128) | | | — | | | (128) | |
| Net income | — | | | — | | | — | | | — | | | — | | | 43,444 | | | 43,444 | | | — | | | 43,444 | |
| Balance at June 30, 2019 | 176,588 | | | $ | 1,384 | | | 34,052 | | | $ | (148,939) | | | $ | 2,164,295 | | | $ | (426,376) | | | $ | 1,590,364 | | | $ | 155,945 | | | $ | 1,746,309 | |
| Preferred Units issued | — | | | — | | | — | | | — | | | — | | | — | | | — | | | 99,000 | | | 99,000 | |
| Preferred Units issuance costs | — | | | — | | | — | | | — | | | — | | | — | | | — | | | (2,500) | | | (2,500) | |
| Preferred Units commitment fees & dividends paid-in-kind | — | | | — | | | — | | | — | | | (5,776) | | | — | | | (5,776) | | | 5,776 | | | — | |
| Stock-based compensation | — | | | — | | | — | | | — | | | 11,387 | | | — | | | 11,387 | | | — | | | 11,387 | |
| Series A Preferred Stock dividends | — | | | — | | | — | | | — | | | (2,721) | | | — | | | (2,721) | | | — | | | (2,721) | |
| Accretion of beneficial conversion feature on Series A Preferred Stock | — | | | — | | | — | | | — | | | (1,682) | | | — | | | (1,682) | | | — | | | (1,682) | |
| Repurchase of common stock | — | | | (48) | | | 4,807 | | | (21,199) | | | — | | | — | | | (21,247) | | | — | | | (21,247) | |
| Restricted stock issued, including payment of tax withholdings using withheld shares | 344 | | | — | | | — | | | — | | | (582) | | | — | | | (582) | | | — | | | (582) | |
| Net income | — | | | — | | | — | | | — | | | — | | | 33,924 | | | 33,924 | | | — | | | 33,924 | |
| Balance at September 30, 2019 | 176,932 | | | $ | 1,336 | | | 38,859 | | | $ | (170,138) | | | $ | 2,164,921 | | | $ | (392,452) | | | $ | 1,603,667 | | | $ | 258,221 | | | $ | 1,861,888 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Common Stock | | | | Treasury Stock | | | | Additional Paid in Capital | | Accumulated Deficit | | Extraction Oil & Gas, Inc. Stockholders' Equity (Deficit) | | Noncontrolling Interest | | Total Stockholders' Equity (Deficit) |
| Shares | | Amount | | Shares | | Amount | | | | | | | | Amount | | |
| Balance at January 1, 2020 | 176,517 | | | $ | 1,336 | | | 38,859 | | | $ | (170,138) | | | $ | 2,156,383 | | | $ | (1,743,208) | | | $ | 244,373 | | | $ | 264,364 | | | $ | 508,737 | |
| | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | |
| Preferred Units commitment fees & dividends paid-in-kind | — | | | — | | | — | | | — | | | (6,160) | | | — | | | (6,160) | | | 6,160 | | | — | |
| | | | | | | | | | | | | | | | | |
| Series A Preferred Stock dividends | — | | | — | | | — | | | — | | | (4,748) | | | — | | | (4,748) | | | — | | | (4,748) | |
| Accretion of beneficial conversion feature on Series A Preferred Stock | — | | | — | | | — | | | — | | | (1,770) | | | — | | | (1,770) | | | — | | | (1,770) | |
| | | | | | | | | | | | | | | | | |
| Restricted stock issued, net of tax withholdings and other | 234 | | | — | | | — | | | — | | | (35) | | | — | | | (35) | | | — | | | (35) | |
| Net income | — | | | — | | | — | | | — | | | — | | | 9,037 | | | 9,037 | | | — | | | 9,037 | |
| Effects of deconsolidation of Elevation Midstream, LLC | — | | | — | | | — | | | — | | | — | | | — | | | — | | | (270,524) | | | (270,524) | |
| Balance at March 31, 2020 | 176,751 | | | $ | 1,336 | | | 38,859 | | | $ | (170,138) | | | $ | 2,143,670 | | | $ | (1,734,171) | | | $ | 240,697 | | | $ | — | | | $ | 240,697 | |
| | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | |
| Stock-based compensation | — | | | — | | | — | | | — | | | 2,560 | | | — | | | 2,560 | | | — | | | 2,560 | |
| Series A Preferred Stock dividends | — | | | — | | | — | | | — | | | (4,001) | | | — | | | (4,001) | | | — | | | (4,001) | |
| Accretion of beneficial conversion feature on Series A Preferred Stock | — | | | — | | | — | | | — | | | (1,817) | | | — | | | (1,817) | | | — | | | (1,817) | |
| | | | | | | | | | | | | | | | | |
| Restricted stock issued, net of tax withholdings and other | 452 | | | — | | | — | | | — | | | (85) | | | — | | | (85) | | | — | | | (85) | |
| Net loss | — | | | — | | | — | | | — | | | — | | | (291,934) | | | (291,934) | | | — | | | (291,934) | |
| Balance at June 30, 2020 | 177,203 | | | $ | 1,336 | | | 38,859 | | | $ | (170,138) | | | $ | 2,140,327 | | | $ | (2,026,105) | | | $ | (54,580) | | | $ | — | | | $ | (54,580) | |
| | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | |
| | | Common Stock | | | | Treasury Stock | | | | Additional Paid in Capital | | | Accumulated Deficit | | | Extraction Oil & Gas, Inc. Stockholders' Equity | | | Noncontrolling interest | | | Total Stockholders' Equity | | | Common Stock | | | Treasury Stock | | | Additional Paid in Capital | | Accumulated Deficit | | Extraction Oil & Gas, Inc. Stockholders' Equity (Deficit) | | Noncontrolling Interest | | Total Stockholders' Equity (Deficit) |
| | Shares | | | Amount | | | Shares | | | Amount | | | | | | | | | Amount | | | | | Shares | | Amount | | Shares | | Amount | | | | | | | | Amount | | |
| Balance at January 1, 2018 | 172,060 | | | $ | 1,718 | | | 165 | | | $ | (2,105) | | | $ | 2,114,795 | | | $ | (497,643) | | | $ | 1,616,765 | | | $ | — | | | $ | 1,616,765 | | |
| Stock-based compensation | 2,794 | | | — | | | — | | | — | | | 15,721 | | | — | | | 15,721 | | | — | | | 15,721 | | |
| Series A Preferred Stock dividends | — | | | — | | | — | | | — | | | (2,721) | | | — | | | (2,721) | | | — | | | (2,721) | | |
| Accretion of beneficial conversion feature on Series A Preferred Stock | — | | | — | | | — | | | — | | | (1,438) | | | — | | | (1,438) | | | — | | | (1,438) | | |
| Repurchase of common stock | — | | | — | | | 166 | | | (2,309) | | | — | | | — | | | (2,309) | | | — | | | (2,309) | | |
| Restricted stock issued, including payment of tax withholdings using withheld shares | 852 | | | — | | | — | | | — | | | (2,305) | | | — | | | (2,305) | | | — | | | (2,305) | | |
| Net loss | — | | | — | | | — | | | — | | | — | | | (51,995) | | | (51,995) | | | — | | | (51,995) | | |
| Balance at March 31, 2018 | 175,706 | | | $ | 1,718 | | | 331 | | $ | (4,414) | | | $ | 2,124,052 | | | $ | (549,638) | | | $ | 1,571,718 | | | $ | — | | | $ | 1,571,718 | | |
| Stock-based compensation | — | | | — | | | — | | | — | | | 17,743 | | | — | | | 17,743 | | | — | | | 17,743 | | |
| Series A Preferred Stock dividends | — | | | — | | | — | | | — | | | (2,722) | | | — | | | (2,722) | | | — | | | (2,722) | | |
| Accretion of beneficial conversion feature on Series A Preferred Stock | — | | | — | | | — | | | — | | | (1,477) | | | — | | | (1,477) | | | — | | | (1,477) | | |
| Repurchase of common stock | — | | | — | | | — | | | — | | | — | | | — | | | — | | | — | | | — | | |
| Restricted stock issued, including payment of tax withholdings using withheld shares | 92 | | | — | | | — | | | — | | | (226) | | | — | | | (226) | | | — | | | (226) | | |
| Net income | — | | | — | | | — | | | — | | | — | | | 8,848 | | | 8,848 | | | — | | | 8,848 | | |
| Balance at June 30, 2018 | 175,798 | | | $ | 1,718 | | | 331 | | $ | (4,414) | | | $ | 2,137,370 | | | $ | (540,790) | | | $ | 1,593,884 | | | $ | — | | | $ | 1,593,884 | | |
| Preferred Units issued | — | | | — | | | — | | | — | | | — | | | — | | | — | | | 148,500 | | | 148,500 | | |
| Balance at January 1, 2019 | | Balance at January 1, 2019 | 176,210 | | | $ | 1,678 | | | 4,543 | | | $ | (32,737) | | | $ | 2,153,661 | | | $ | (375,788) | | | $ | 1,746,814 | | | $ | 147,872 | | | $ | 1,894,686 | |
| Preferred Units issuance costs | Preferred Units issuance costs | — | | | — | | | — | | | — | | | — | | | — | | | — | | | (7,933) | | | (7,933) | | Preferred Units issuance costs | — | | | — | | | — | | | — | | | — | | | — | | | — | | | (10) | | | (10) | |
| Preferred Units commitment fees & dividends paid-in-kind | Preferred Units commitment fees & dividends paid-in-kind | — | | | — | | | — | | | — | | | (3,305) | | | — | | | (3,305) | | | 3,305 | | | — | | Preferred Units commitment fees & dividends paid-in-kind | — | | | — | | | — | | | — | | | (3,975) | | | — | | | (3,975) | | | 3,975 | | | — | |
| Stock-based compensation | Stock-based compensation | — | | | — | | | — | | | — | | | 17,420 | | | — | | | 17,420 | | | — | | | 17,420 | | Stock-based compensation | — | | | — | | | — | | | — | | | 13,008 | | | — | | | 13,008 | | | — | | | 13,008 | |
| Series A Preferred Stock dividends | Series A Preferred Stock dividends | — | | | — | | | — | | | — | | | (2,721) | | | — | | | (2,721) | | | — | | | (2,721) | | Series A Preferred Stock dividends | — | | | — | | | — | | | — | | | (2,721) | | | — | | | (2,721) | | | — | | | (2,721) | |
| Accretion of beneficial conversion feature on Series A Preferred Stock | Accretion of beneficial conversion feature on Series A Preferred Stock | — | | | — | | | — | | | — | | | (1,515) | | | — | | | (1,515) | | | — | | | (1,515) | | Accretion of beneficial conversion feature on Series A Preferred Stock | — | | | — | | | — | | | — | | | (1,596) | | | — | | | (1,596) | | | — | | | (1,596) | |
| Repurchase of common stock | Repurchase of common stock | — | | | — | | | 154 | | | (2,125) | | | — | | | — | | | (2,125) | | | — | | | (2,125) | | Repurchase of common stock | — | | | (77) | | | 7,824 | | | (32,135) | | | — | | | — | | | (32,212) | | | — | | | (32,212) | |
| Restricted stock issued, including payment of tax withholdings using withheld shares | 63 | | | — | | | — | | | — | | | (331) | | | — | | | (331) | | | — | | | (331) | | |
| Restricted stock issued, net of tax withholdings | | Restricted stock issued, net of tax withholdings | 270 | | | — | | | — | | | — | | | (454) | | | — | | | (454) | | | — | | | (454) | |
| Net loss | | Net loss | — | | | — | | | — | | | — | | | — | | | (94,032) | | | (94,032) | | | — | | | (94,032) | |
| Balance at March 31, 2019 | | Balance at March 31, 2019 | 176,480 | | | $ | 1,601 | | | 12,367 | | $ | (64,872) | | | $ | 2,157,923 | | | $ | (469,820) | | | $ | 1,624,832 | | | $ | 151,837 | | | $ | 1,776,669 | |
| Preferred Units issuance costs and discount | | Preferred Units issuance costs and discount | — | | | — | | | — | | | — | | | — | | | — | | | — | | | 10 | | | 10 | |
| Preferred Units commitment fees & dividends paid-in-kind | | Preferred Units commitment fees & dividends paid-in-kind | — | | | — | | | — | | | — | | | (4,098) | | | — | | | (4,098) | | | 4,098 | | | — | |
| Stock-based compensation | | Stock-based compensation | — | | | — | | | — | | | — | | | 14,957 | | | — | | | 14,957 | | | — | | | 14,957 | |
| Series A Preferred Stock dividends | | Series A Preferred Stock dividends | — | | | — | | | — | | | — | | | (2,722) | | | — | | | (2,722) | | | — | | | (2,722) | |
| Accretion of beneficial conversion feature on Series A Preferred Stock | | Accretion of beneficial conversion feature on Series A Preferred Stock | — | | | — | | | — | | | — | | | (1,637) | | | — | | | (1,637) | | | — | | | (1,637) | |
| Repurchase of common stock | | Repurchase of common stock | — | | | (217) | | | 21,685 | | | (84,067) | | | — | | | — | | | (84,284) | | | — | | | (84,284) | |
| Restricted stock issued, net of tax withholdings | | Restricted stock issued, net of tax withholdings | 108 | | | — | | | — | | | — | | | (128) | | | — | | | (128) | | | — | | | (128) | |
| Net income | Net income | — | | | — | | | — | | | — | | | — | | | 65,150 | | | 65,150 | | | — | | | 65,150 | | Net income | — | | | — | | | — | | | — | | | — | | | 43,444 | | | 43,444 | | | — | | | 43,444 | |
| Balance at September 30, 2018 | 175,861 | | | $ | 1,718 | | | 485 | | $ | (6,539) | | | $ | 2,146,918 | | | $ | (475,640) | | | $ | 1,666,457 | | | $ | 143,872 | | | $ | 1,810,329 | | |
| Balance at June 30, 2019 | | Balance at June 30, 2019 | 176,588 | | | $ | 1,384 | | | 34,052 | | $ | (148,939) | | | $ | 2,164,295 | | | $ | (426,376) | | | $ | 1,590,364 | | | $ | 155,945 | | | $ | 1,746,309 | |
|
THE ACCOMPANYING NOTES ARE AN INTEGRAL PART OF
THESE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
EXTRACTION OIL & GAS, INC.
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(In thousands)
(Unaudited)
| | | | | | | | | | | |
| For the Nine Months Ended September 30, | | |
| 2019 | | 2018 |
| Cash flows from operating activities: | As restated | | |
| Net income (loss) | $ | (16,664) | | | $ | 22,003 | |
| Reconciliation of net income (loss) to net cash provided by operating activities: | | | |
| Depletion, depreciation, amortization and accretion | 352,134 | | | 310,296 | |
| Abandonment and impairment of unproved properties | 26,166 | | | 15,463 | |
| Impairment of long lived assets | 11,233 | | | 16,294 | |
| Gain on sale of property and equipment | (319) | | | (59,849) | |
| Gain on sale of assets of unconsolidated subsidiary | (1,010) | | | (83,612) | |
| Gain on repurchase of 2026 Senior Notes | (10,486) | | | — | |
| Amortization of debt issuance costs | 3,799 | | | 12,303 | |
| Non-cash lease expense | 7,739 | | | — | |
| Contract asset (liability) | 22,175 | | | — | |
| Deferred rent | — | | | 442 | |
| Commodity derivatives (gain) loss | (39,383) | | | 175,752 | |
| Settlements on commodity derivatives | (18,527) | | | (93,482) | |
| Premiums paid on commodity derivatives | (2,852) | | | (17,271) | |
| Earnings in unconsolidated subsidiaries | (1,217) | | | (1,886) | |
| Distributions from unconsolidated subsidiaries | 2,630 | | | 1,684 | |
| Make-whole premium paid on 2021 Senior Notes | — | | | 35,600 | |
| Deferred income tax expense | 900 | | | 12,300 | |
| Stock-based compensation | 39,306 | | | 50,883 | |
| Changes in current assets and liabilities: | | | |
| Accounts receivable—trade | (1,395) | | | 4,573 | |
| Accounts receivable—oil, natural gas and NGL sales | 16,293 | | | (13,865) | |
| Inventory, prepaid expenses and other | 1,078 | | | (637) | |
| Accounts payable and accrued liabilities | (6,469) | | | (14,780) | |
| Revenue payable | (21,723) | | | 60,946 | |
| Production taxes payable | 12,211 | | | 49,657 | |
| Accrued interest payable | (4,977) | | | (5,015) | |
| Asset retirement expenditures | (14,081) | | | (9,437) | |
| Net cash provided by operating activities | 356,561 | | | 468,362 | |
| Cash flows from investing activities: | | | |
| Oil and gas property additions | (526,187) | | | (774,787) | |
| Sale of property and equipment | 41,982 | | | 72,345 | |
| Gathering systems and facilities additions | (169,180) | | | (41,359) | |
| Other property and equipment additions | (32,575) | | | (11,944) | |
| Investment in unconsolidated subsidiaries | (22,487) | | | (6,000) | |
| Distributions from unconsolidated subsidiary, return of capital | 569 | | | — | |
| Sale of assets of unconsolidated subsidiary | 1,010 | | | 83,612 | |
| Net cash used in investing activities | (706,868) | | | (678,133) | |
| Cash flows from financing activities: | | | |
| Borrowings under credit facility | 375,000 | | | 590,000 | |
| Repayments under credit facility | (110,000) | | | (390,000) | |
| Proceeds from the issuance of 2026 Senior Notes | — | | | 739,664 | |
| Repayments of 2021 Senior Notes | — | | | (550,000) | |
| Make-whole premium paid on 2021 Senior Notes | — | | | (35,600) | |
| Repurchase of 2026 Senior Notes | (39,325) | | | — | |
| Repurchase of commons stock | (137,743) | | | (4,434) | |
| Payment of employee payroll withholding taxes | (1,164) | | | (2,862) | |
| Dividends on Series A Preferred Stock | (8,164) | | | (8,164) | |
| Debt and equity issuance costs | (2,055) | | | (3,103) | |
| Proceeds from issuance of Preferred Units | 99,000 | | | 148,500 | |
| Preferred Unit issuance costs | (2,500) | | | (6,933) | |
| Net cash provided by financing activities | 173,049 | | | 477,068 | |
| (Decrease) increase in cash and cash equivalents | (177,258) | | | 267,297 | |
| Cash, cash equivalents and restricted cash at beginning of period | 234,986 | | | 6,768 | |
| Cash, cash equivalents and restricted cash at end of the period | $ | 57,728 | | | $ | 274,065 | |
| Supplemental cash flow information: | | | |
| Property and equipment included in accounts payable and accrued liabilities | $ | 158,178 | | | $ | 148,156 | |
| Cash paid for interest | $ | 71,878 | | | $ | 66,673 | |
| Issuance of promissory note to unconsolidated subsidiary | $ | — | | | $ | 35,329 | |
| Extinguishment of promissory note in exchange for equity with unconsolidated subsidiary | $ | — | | | $ | (35,329) | |
| Accretion of beneficial conversion feature of Series A Preferred Stock | $ | 4,915 | | | $ | 4,429 | |
| Preferred Units paid-in-kind commitment fees and dividends | $ | 13,849 | | | $ | 3,305 | |
THE ACCOMPANYING NOTES ARE AN INTEGRAL PART OF
THESE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
EXTRACTION OIL & GAS, INC.
NOTES TO THE UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(DEBTOR-IN-POSSESSION)
Note 1—Business and Organization
Extraction Oil & Gas, Inc. (the “Company”"Company" or “Extraction”"Extraction") is an independent oil and gas company focused on the acquisition, development and production of oil, natural gas and NGLnatural gas liquids (“NGLs”) reserves in the Rocky Mountain region, primarily in the Wattenberg Field of the Denver-Julesburg Basin (the “DJ Basin”"DJ Basin") of Colorado. The Company and its subsidiaries are focused on the acquisition, development and production of oil, natural gas and NGL reserves in the Rocky Mountain region,Colorado, as well as the designconstruction and support of midstream assets to gather and process crude oil, natural gas and gas production focusedwater production. As described in the DJ Basinsection titled Voluntary Reorganization under Chapter 11 of Colorado. Extraction isthe Bankruptcy Code below, during the second quarter of 2020, the Company filed for bankruptcy and, as a public company listed for trading onresult, was delisted from the NASDAQ Global Select Market on June 25, 2020 and began trading on the Pink Open Market under the symbol "XOG""XOGAQ."
Voluntary Reorganization under Chapter 11 of the Bankruptcy Code
On June 14, 2020 (the “Petition Date”), Extraction and its wholly owned subsidiaries (collectively, the “Debtors”), filed voluntary petitions for relief under chapter 11 ("Chapter 11") of title 11 of the United States Code (the “Bankruptcy Code”) in the United States Bankruptcy Court for the District of Delaware (the “Bankruptcy Court”). The Debtor's Chapter 11 cases (the “Chapter 11 Cases”) are being jointly administered under the caption In re Extraction Oil & Gas., et al. Case No. 20-11548 (CSS).
The Debtors continue to operate their businesses and manage their properties as “debtors-in-possession” under the jurisdiction of the Bankruptcy Court and in accordance with the applicable provisions of the Bankruptcy Code and orders of the Bankruptcy Court. In general, as debtors-in-possession under the Bankruptcy Code, the Debtors are authorized to continue to operate as an ongoing business; however, they may not engage in transactions outside the ordinary course of business without the prior approval of the Bankruptcy Court. To that end, to ensure the Company’s ability to continue operating in the ordinary course of business during the pendency of the Chapter 11 Cases and minimize the effect of the Chapter 11 Cases on the Company’s customers and employees, the Company filed with the Bankruptcy Court, and the Bankruptcy Court approved, motions (the “First Day Motions”) seeking a variety of relief. Pursuant to the First Day Motions, the Bankruptcy Court authorized the Company to conduct its business in the ordinary course, including to, among other things, pay employee wages and benefits, continue to operate the cash management system and honor certain prepetition obligations related thereto, pay certain vendors and suppliers for goods and services provided both before and after the Petition Date, and other customary operational and financing relief.
The commencement of a voluntary proceeding in bankruptcy constituted an immediate event of default under the Credit Agreement (as defined in Note 6—Long-Term Debt) and the indentures governing the Company’s Senior Notes (as defined below), resulting in the automatic and immediate acceleration of all of the Company’s debt outstanding under the Credit Agreement and Senior Notes. Accordingly, the Company has classified its outstanding senior note debt as liabilities subject to compromise on its condensed consolidated balance sheet as of June 30, 2020. The Credit Facility (as defined in Note 6—Long-Term Debt) was not classified as liabilities subject to compromise because it is fully secured and is expected to be unimpaired. Please refer to Note 4—Liabilities Subject to Compromise for more information. Pursuant to the Bankruptcy Code and as described in Note 6—Long-Term Debt, the filing of the Chapter 11 Cases automatically stayed most actions against the Debtors, including most actions to collect indebtedness incurred prior to the Petition Date or to exercise control over the Debtors’ property.
Restructuring Support Agreement
On June 14, 2020, the Company entered into a Restructuring Support Agreement (the “RSA”) with (i) significant holders of its 7.375% senior unsecured notes due 2024 (the “2024 Senior Notes”) issued pursuant to that certain indenture, dated as of August 1, 2017, by and among Extraction, as issuer, certain guarantors party thereto and Wilmington Savings Fund Society, FSB, as trustee (such trustee, “WSFS” and such indenture, the “2024 Senior Notes Indenture”) and (ii) significant holders (such holders, together with the foregoing significant holders under the 2024 Senior Notes, the “Consenting Stakeholders”) of its 5.625% senior unsecured notes due 2026 (the “2026 Senior Notes” and, together with the 2024 Senior Notes, the “Senior Notes”) issued pursuant to that certain indenture, dated as of January 25, 2018, by and among Extraction, the subsidiary guarantors party thereto and WSFS, as trustee (the “2026
Senior Notes Indenture” and, together with the 2024 Senior Notes Indenture, the “Senior Notes Indentures”). The RSA contemplates a financial restructuring of the existing indebtedness of, and equity interests in, the Company to be effectuated through a joint Chapter 11 plan of reorganization (the “Restructuring Plan”) that effectuates (a) a sale to, or combination or merger with, a third party involving all or substantially all of the Company’s restructured equity or assets pursuant to one or more transactions that the Company determines, in the exercise of its business judgment, satisfies certain requirements set forth in the RSA (a “Combination Transaction”) or (b) a standalone reorganization (the “Stand-Alone Restructuring”).
Restructuring Plan and Disclosure Statement
On July 30, 2020, the Debtors filed a proposed Restructuring Plan and a related Disclosure Statement (the “Disclosure Statement”) describing the Restructuring Plan and the solicitation of votes to approve the same from certain of the Debtors’ creditors with respect to the Chapter 11 Cases. The hearing to consider approval of the Disclosure Statement is currently scheduled for September 3, 2020.
The Restructuring Plan contemplates, among other things, the following:
•holders of claims under the Amended and Restated Credit Agreement, dated as of August 16, 2017, by and among Extraction, the subsidiary guarantors party thereto, the lenders from time to time thereto, and Wells Fargo Bank, National Association, as administrative agent (as may be amended, restated, supplemented, or otherwise modified from time to time, the “Credit Agreement”), receiving either: (i) on a dollar for dollar basis, their pro rata share of the revolving loans, term loans, letter-of-credit participations, and other fees under an exit facility or (ii) payment in full in cash from (a) if the Combination Transaction is pursued, (A) the proceeds of the exit facility and/or (B) the consideration from the Combination Transaction or (b) if the Stand-Alone Restructuring occurs, the proceeds of (A) the exit facility and/or (B) the Equity Rights Offering (as defined in the Restructuring Plan);
•holders of claims under the Senior Notes Indentures (“Senior Notes Claims”) receiving: (i) in the event of a Combination Transaction, their pro rata share of 97% of (a) the new common stock (the “New Common Stock”) of Extraction, as reorganized pursuant to and under the Restructuring Plan (“Reorganized Extraction”), pro forma for the Combination Transaction, subject to dilution by the Management Incentive Plan (as defined below), the Backstop Commitment Premium (as defined in the RSA), and the New Warrants (as defined below) (such allocation, the “Equity Allocation”) or (b) the cash proceeds from the Combination Transaction (the “Alternative Allocation”); or (ii) in the event of a Stand-Alone Restructuring, their pro rata share of (a) 97% of the Equity Allocation and (b) 97% of the subscription rights to purchase New Common Stock in the Equity Rights Offering;
•holders of trade claims receiving: (i) if a Combination Transaction is pursued, express assumption of such allowed trade claims by the partner(s) to the Combination Transaction in accordance with the terms of the Combination Transaction agreement and related documents or (ii) if the Stand-Alone Restructuring is pursued, payment in full on the Plan Effective Date or otherwise in the ordinary course of the Debtors’ business;
•holders of claims arising from non-funded debt general unsecured obligations receiving, (i) in the event of a Combination Transaction, their pro rata share of 97% of (a) the Equity Allocation pro forma for the Combination Transaction and/or (b) the Alternative Allocation; or (ii) in the event of a Stand-Alone Restructuring, their pro rata share of 97% of the Equity Allocation.
•holders of existing preferred interests in the Company receiving: (i) in the event of a Combination Transaction, their pro rata share of (a) 1.5% of (x) the Equity Allocation pro forma for the Combination Transaction and/or (y) the Alternative Allocation and (b) 50% of new tranche A and tranche B warrants (the “New Warrants”); or (ii) in the event of a Stand-Alone Restructuring, (a) 1.5% of the Equity Allocation, (b) 1.5% of the subscription rights to purchase New Common Stock in the Equity Rights Offering and (c) 50% of the New Warrants;
•holders of existing common interests in the Company receiving: (i) in the event of a Combination Transaction, their pro rata share of (a) 1.5% of (x) the Equity Allocation pro forma for the Combination Transaction and/or
(y) the Alternative Allocation and (b) 50% of the New Warrants; or (ii) in the event of a Stand-Alone Restructuring, (a) 1.5% of the Equity Allocation, (b) 1.5% of the subscription rights to purchase New Common Stock in the Equity Rights Offering and (c) 50% of the New Warrants;
•holders of claims arising from the DIP Credit Facility (as defined in Note 6—Long-Term Debt) receiving cash or such other consideration as the DIP Lenders (as defined in Note 6—Long-Term Debt) agree in their sole discretion;
•cash payment in full of all administrative expense claims, priority tax claims, other priority claims, and other secured claims or other such treatment rendering such claims unimpaired, including reinstatement pursuant to section 1124 of the Bankruptcy Code or delivery of the collateral securing any such secured claim and payment of any interest required under section 506(b) of the Bankruptcy Code; and
•(i) in the event of a Combination Transaction, customary cash incentives will be provided to the management with an aggregate value that is no less than the value of the MIP Equity (as defined below), or (ii) in the event of a Stand-Alone Restructuring, the Restructuring Plan will provide for the establishment of a post-emergence management incentive plan to be adopted by the New Board (the “Management Incentive Plan”), which will include (a) restricted stock units, options, New Common Shares, or other rights exercisable, exchangeable, or convertible into New Common Shares representing up to 10% of the New Common Shares on a fully diluted and fully distributed basis (the “MIP Equity”) and (b) other terms and conditions customary for similar type equity plans.
Information contained in the Restructuring Plan and the Disclosure Statement is subject to change, whether as a result of amendments or supplements to the Restructuring Plan or Disclosure Statement, third-party actions, or otherwise, and should not be relied upon by any party. There is no guarantee the RSA can be implemented and the Restructuring Plan approved.
The information presented in this section is not a solicitation to accept or reject the Restructuring Plan. Any such solicitation will be made pursuant to and in accordance with the Disclosure Statement and applicable law, including orders of the Bankruptcy Court. Capitalized terms used but not specifically defined in this section have the meanings specified for such terms in the Restructuring Plan and Disclosure Statement, as applicable.
Tax Attributes and Net Operating Loss Carryforwards
The Company has substantial tax net operating loss carryforwards and other tax attributes. Under the U.S. Internal Revenue Code of 1986, as amended (the “Code”), our ability to use these net operating losses and other tax attributes may be limited if the Company experiences an “ownership change”, as determined under Section 382 of the Code. Accordingly, on July 13, 2020, the Company obtained a final order from the Bankruptcy Court that is intended to prevent an ownership change during the pendency of the Chapter 11 Cases and therefore protect the Company's ability to use its tax attributes by imposing certain notice procedures and transfer restrictions on the trading of the Company’s existing common stock and preferred stock.
In general, the order applies to any person or entity that, directly or indirectly, beneficially owns (or would beneficially own as a result of a proposed transfer) at least 4.5% of the Company’s common stock or preferred stock. Such persons are required to notify the Company and the Bankruptcy Court before effecting a transaction involving the Company's common stock or preferred stock, and the Company has the right to seek an injunction to prevent the transaction if it might adversely affect the Company's ability to use its tax attributes. The order also requires any person or entity that, directly or indirectly, beneficially owns at least 50% of the Company’s common stock or preferred stock to notify the Company and the Bankruptcy Court prior to claiming any deduction for worthlessness of the Company's common stock or preferred stock for a tax year ending before the Company’s emergence from chapter 11 protection and the Company has the right to seek an injunction to prevent the transaction if it might adversely affect the Company's ability to use its tax attributes.
Any purchase, sale or other transfer of, or any claim of a deduction for worthlessness with respect to, the Company's common stock or preferred stock in violation of the restrictions of the order is null and void ab initio as an act
in violation of a Bankruptcy Court order and would therefore confer no rights on a proposed transferee or such holder, as applicable.
Ability to Continue as a Going Concern
The condensed consolidated financial statements have been prepared on a going concern basis of accounting, which contemplates continuity of operations, realization of assets and satisfaction of liabilities and commitments in the normal course of business. The consolidated financial statements do not reflect any adjustments that might result if the Company is unable to continue as a going concern.
As discussed above, the filing of the Chapter 11 Cases constituted an event of default under the Company’s outstanding debt agreements, which resulted in the automatic and immediate acceleration of all of the Company’s debt outstanding under the Credit Agreement and Senior Notes. The Company projects that it will not have sufficient cash on hand or available liquidity to repay such debt. These conditions and events raise substantial doubt about the Company’s ability to continue as a going concern.
The Company’s ability to continue as a going concern is contingent upon, among other things, its ability to, subject to the Bankruptcy Court’s approval, implement the Restructuring Plan, successfully emerge from the Chapter 11 Cases and generate sufficient liquidity from the Restructuring to meet its obligations and operating needs. As a result of risks and uncertainties related to (i) the Company’s ability to obtain requisite support for the Restructuring Plan from various stakeholders, and (ii) the effects of disruption from the Chapter 11 Cases making it more difficult to maintain business, financing and operational relationships, the Company has concluded that management’s plans do not alleviate substantial doubt regarding the Company’s ability to continue as a going concern.
The condensed consolidated financial statements do not include any adjustments relating to the recoverability and classification of recorded asset amounts or the amounts and classification of liabilities that might result from the outcome of this uncertainty.
Deconsolidation of Elevation Midstream, LLC
Elevation Midstream, LLC (“Elevation”("Elevation"), a Delaware limited liability company, and an unrestricted subsidiary of the Company, is focused on the construction and operation of gathering systems and facilities operations to serve the development of acreage in the Company’s Hawkeye and Southwest Wattenberg areas. Midstream assets of Elevation are represented as the gathering systems and facilities line item within the condensed consolidated balance sheets. Assheets for any periods ended on or prior to December 31, 2019.
During the first quarter of September 30, 2019, these2020, Elevation's then non-controlling interest owner, which owned 100% of Elevation's preferred stock, per contractual agreement, expanded Elevation's then five member board of managers by four seats and filled them with managers of their choosing (the "Board Expansion"). Because Extraction had the right to appoint only three of the managers of Elevation before and after Board Expansion, Extraction determined the Company had lost voting control of Elevation, and on March 16, 2020 deconsolidated Elevation and began accounting for the entity as an equity method investment. Though Extraction determined control of Elevation was lost under the voting interest model of consolidation, the Company also determined significant influence was not lost due to (1) Extraction owning 100% of the common stock, (2) Extraction appointing three of the nine managers of Elevation and (3) Extraction's continuing involvement in the day-to-day operation of Elevation through a management services agreement. Because Extraction also determined the Company is not the primary beneficiary, Elevation Midstream, LLC is not a variable interest entity.
Extraction elected the fair value option to remeasure the Elevation equity method investment and determined it had no fair value. The Company recorded a $73.1 million loss on deconsolidation of the investment in the condensed consolidated statements of operations for the three months ended March 31, 2020. Also during the three months ended March 31, 2020, Elevation determined certain gathering systems and facilities operations were not in service, therefore, there were no associated revenuesimpaired by $50.3 million as a result of the abandonment of certain projects. In accordance with Accounting Standards Codification ("ASC") Topic 323-10-35-20: Investments—equity method and joint ventures, Extraction discontinued applying the equity method investment for Elevation as the three and nine months then ended. On October 3, 2019, Elevation commenced moving crude oil, natural gas and water through its Badger central gathering facility, which enables Extraction to efficiently transport its crude oil and natural gas production along with water used duringimpairment charge would have reduced the completion process. The use of this gathering facility allows for the elimination of oil or water storage on the well pad site and reduces truck traffic, which minimizes the impact to the surrounding environment and communities.investment below zero.
On July 10, 2019, Elevation closed on the issuanceMay 1, 2020, Elevation's board of an additional 100,000 Preferred Units of Elevation (the "Elevation Preferred Units") under an existing securities purchase agreement with a third party, pursuant to which Elevation had agreed to sell an additional 100,000 Elevation Preferred Unitsmanagers issued 1,530,000,000 common units at a price of $990$0.01 per unit to certain of Elevation's members other than Extraction (the "Capital Raise"). The Capital Raise caused Extraction's ownership of Elevation Preferred Unit with an aggregate liquidation preference of $100.0 million, and resulting in net proceeds of approximately $96.5 million, after deducting discounts and related offering expenses. These Elevation Preferred Units are non-recourse to Extraction.
On November 19, 2018, the Company announced that the Board of Directors had authorizedbe diluted to less than 0.01%. As a program to repurchase up to $100.0 millionresult of the Company's common stock ("Stock Repurchase Program"). On April 1, 2019, the Company announced the Board of Directors had authorized an extension and increase to the ongoing Stock Repurchase Program bringing the total amount authorized to $163.2 million ("Extended Stock Repurchase Program"). Prior to commencing the Extended Stock Repurchase Program, the Company had purchased approximately 13.0 million shares of its common stockCapital Raise, beginning in May 2020 Extraction began accounting for $63.2 millionElevation under the Stock Repurchase Program.cost method of accounting. The Company was authorizedreserves all rights related to repurchase an incremental $100.0 million in common stock, which repurchases were completed in the third quarteractions taken by Elevation’s board of 2019, bringing the total amount of common stock repurchased to $163.2 million. During the three and nine months ended September 30, 2019, the Company repurchased approximately 4.8 million and 34.1 million shares of its common stock for $21.2 million and $136.9 million, respectively.managers.
Note 2—Basis of Presentation, Restatement, Significant Accounting Policies and Recent Accounting Pronouncements
Basis of Presentation
The unaudited condensed consolidated financial statements include the accounts of the Company, including its wholly owned subsidiaries. All significant intercompany balances and transactions have been eliminated in consolidation. The financial statements included herein were prepared from the records of the Company in accordance with accounting principles generally accepted accounting principles in the United States of America (“GAAP”) and the Securities and Exchange Commission rules and regulation for interim financial reporting. In the opinion of management, all adjustments, consisting primarily of normal recurring accruals that are considered necessary for a fair statement of the unaudited condensed consolidated financial information, have been included. However, operating results for the period presented are not necessarily indicative of the results that may be expected for a full year. Interim condensed consolidated financial statements and the year-end balance sheetsheets do not include all of the information and notes required by GAAP for audited annual consolidated financial statements. These unaudited condensed consolidated financial statements should be read in conjunction with the Company’s audited consolidated financial statements and notes included in the Company’s Annual Report.
Restatement of Previously Issued Unaudited Condensed Consolidated Financial Statements
The Company concluded subsequent to filingReport on Form 10Q/A Amendment No. 1 with the SEC that one of the Company's revenue contracts should have been accounted for with an earlier termination date due to an automatic renewal provision. The contract term impacts the amount of consideration that can be included in the transaction price. The Company had accounted
for revenue relating to the contract assuming a term ending in August 2023. Upon subsequent review, the Company determined that the proper accounting treatment pursuant to ASC 606 - Revenue from Contracts with Customers would have been to evaluate the contract with a term ending on April 30, 2021 because the contract may be terminated by either party with no penalty effective as of such date. However, the contract cannot be extended beyond October 2026. Accounting10-K for the contract with an earlier termination date resulted in a decrease to the Company’s revenues of $20.0 million for the three and nine monthsyear ended September 30,December 31, 2019 and an increase to the Company's assets and liabilities of $12.3 million and $32.3 million as of September 30, 2019, respectively. Corrections to prior periods were immaterial. The following tables present the effect of the correction discussed above on selected line items of our previously reported condensed consolidated balance sheet as of September 30, 2019, and the Company's condensed consolidated statements of operations for the three and nine months ended September 30, 2019 and the Company's condensed consolidated statements of cash flows for the nine months ended September 30, 2019 (in thousands)(“Annual Report”).
Condensed Consolidated Balance Sheet
| | | | | | | | | | | | | | | | | |
| September 30, 2019 | | | | |
| As Reported | | Adjustments | | As Restated |
| Inventory, prepaid expenses and other | $ | 19,489 | | | $ | 9,365 | | | $ | 28,854 | |
| Total Current Assets | 268,542 | | | 9,365 | | | 277,907 | |
| Other non-current assets | 66,346 | | | 2,944 | | | 69,290 | |
| Total Non-Current Assets | 107,866 | | | 2,944 | | | 110,810 | |
| Total Assets | 4,429,158 | | | 12,309 | | | $ | 4,441,467 | |
| | | | | |
| Accounts payable and accrued liabilities | 216,193 | | | 1 | | | 216,194 | |
| Total Current Liabilities | 471,108 | | | 1 | | | 471,109 | |
| Other non-current liabilities | 23,412 | | | 32,340 | | | 55,752 | |
| Deferred tax liability | 115,876 | | | (5,800) | | | 110,076 | |
| Total Non-Current Liabilities | 1,912,648 | | | 26,540 | | | 1,939,188 | |
| Total Liabilities | 2,383,756 | | | 26,541 | | | 2,410,297 | |
| Accumulated deficit | (378,220) | | | (14,232) | | | (392,452) | |
| Total Extraction Oil & Gas, Inc. Stockholders' Equity | 1,617,899 | | | (14,232) | | | 1,603,667 | |
| Total Stockholders' Equity | 1,876,120 | | | (14,232) | | | 1,861,888 | |
| Total Liabilities and Stockholders' Equity | $ | 4,429,158 | | | $ | 12,309 | | | $ | 4,441,467 | |
Condensed Consolidated Statements of Operations
| | | | | | | | | | | | | | | | | |
| Three Months Ended September 30, 2019 | | | | |
| As Reported | | Adjustments | | As Restated |
| Oil sales | $ | 171,074 | | | $ | (20,032) | | | $ | 151,042 | |
| Total Revenues | 196,974 | | | (20,032) | | | 176,942 | |
| Operating Income (Loss) | 2,687 | | | (20,032) | | | (17,345) | |
| Income (Loss) Before Income Taxes | 68,756 | | | (20,032) | | | 48,724 | |
| Income tax expense | (20,600) | | | 5,800 | | | (14,800) | |
| Net Income (Loss) | 48,156 | | | (14,232) | | | 33,924 | |
| Net Income (Loss) Attributable to Extraction Oil & Gas, Inc. | 42,380 | | | (14,232) | | | 28,148 | |
| Net Income (Loss) Attributable to Common Shareholders | 37,977 | | | (14,232) | | | 23,745 | |
| Income (Loss) Per Common Share (Note 10) | 0.28 | | | (0.11) | | | 0.17 | |
| | | | | | | | | | | | | | | | | |
| Nine Months Ended September 30, 2019 | | | | |
| As Reported | | Adjustments | | As Restated |
| Oil sales | $ | 521,623 | | | $ | (20,032) | | | $ | 501,591 | |
| Total Revenues | 640,948 | | | (20,032) | | | 620,916 | |
| Operating Income (Loss) | 16,344 | | | (20,032) | | | (3,688) | |
| Income (Loss) Before Income Taxes | 4,268 | | | (20,032) | | | (15,764) | |
| Income tax expense | (6,700) | | | 5,800 | | | (900) | |
| Net Income (Loss) | (2,432) | | | (14,232) | | | (16,664) | |
| Net Income (Loss) Attributable to Extraction Oil & Gas, Inc. | (16,281) | | | (14,232) | | | (30,513) | |
| Net Income (Loss) Attributable to Common Shareholders | (29,360) | | | (14,232) | | | (43,592) | |
| Income (Loss) Per Common Share (Note 10) | (0.19) | | | (0.09) | | | (0.28) | |
Condensed Consolidated Statements of Cash Flows
| | | | | | | | | | | | | | | | | |
| Nine Months Ended September 30, 2019 | | | | |
| As Reported | | Adjustments | | As Restated |
| Net income (loss) | $ | (2,432) | | | $ | (14,232) | | | $ | (16,664) | |
| Contract asset (liability) | — | | | 22,175 | | | 22,175 | |
| Deferred income tax expense | 6,700 | | | (5,800) | | | 900 | |
| Inventory, prepaid expenses and other | (3,479) | | | 4,557 | | | 1,078 | |
| Accounts payable and accrued liabilities | 231 | | | (6,700) | | | (6,469) | |
| Net cash provided by operating activities | 356,561 | | | — | | | 356,561 | |
Significant Accounting Policies
The significant accounting policies followed by the Company are set forth in Note 2 to the Company’s consolidated financial statements in its Annual Report and are supplemented by the notes to the unaudited condensed consolidated financial statements in this report. These unaudited
Beginning after the Petition Date, the Company has applied ASC Topic 852 — Reorganizations in preparing the condensed consolidated financial statements. ASC 852 requires the financial statements, should be read in conjunctionfor periods subsequent to the Chapter 11 Cases' filing date, to distinguish transactions and events that are directly associated with the reorganization from the ongoing operations of the business. Accordingly, certain revenues and expenses incurred during the bankruptcy proceedings, including unamortized debt issuance costs associated with debt classified as liabilities subject to compromise, are recorded as reorganization items. In addition, pre-petition obligations that may be impacted by the chapter 11 process have been classified on the condensed consolidated financial statements and notes included inbalance sheets as liabilities subject to compromise. These liabilities are reported at the Company’s Annual Report.amounts the Company anticipates will be allowed by the Bankruptcy Court, even if they may be settled for lesser amounts. See below for more information regarding reorganization items.
RevenueGAAP requires certain additional reporting for financial statements prepared between the Petition Date and the date that the Company emerges from bankruptcy, including:
During•Reclassification of pre-petition liabilities that are unsecured, under-secured or where it cannot be determined that the third quarter of 2019, the Company allocated $22.2 millionliabilities are fully secured to a satisfied performance obligation, recognized within oil sales for the three and nine months ended September 30, 2019, pursuant to Accounting Standards Codification ("ASC") 606, Revenue Recognition. Also, during the third quarter of 2019, the Company estimated a performance obligation under ASC 606 - Revenue from Contracts with Customers of $39.0 million, of which $3.4 million is recorded in accounts payable and accrued liabilities and $35.6 million is recorded in other non-current liabilities. A corresponding asset was recorded in the amount of $16.9 million, of which $10.4 million is recorded in inventory, prepaid expenses and other and $6.5 million is recorded in other non-current assets. These amounts were includedseparate line item in the condensed consolidated balance sheet as of September 30, 2019.
Leases
The Company accounts for leases•Segregation of reorganization items as a separate line in accordance with ASC 842, Leases, which it adopted on January 1, 2019, applying the modified retrospective transition approach ascondensed consolidated statements of the effective dateoperations outside of adoption (see "Recent Accounting Pronouncements" for impacts of adoption).income from continuing operations.
Debtor-In-Possession
The Debtors are currently operating as debtors in possession in accordance with the applicable provisions of the Bankruptcy Code. The Bankruptcy Court has approved motions filed by the Debtors that were designed primarily to mitigate the impact of the Chapter 11 Cases on the Company’s operations, customers and employees. As a result, the Company enters into operating leasesis able to conduct normal business activities and pay all associated obligations for the period following its bankruptcy filing in the ordinary course of business and is authorized to pay and has paid certain drilling equipment, completions equipment, equipment ancillarypre-petition obligations, including, among other things, for employee wages and benefits and certain goods and services provided. During the Chapter 11 Cases, transactions outside the ordinary course of business require prior approval of the Bankruptcy Court.
Automatic Stay
Subject to drillingcertain specific exceptions under the Bankruptcy Code, the Chapter 11 Cases automatically stayed most judicial or administrative actions against the Debtors and completions, office facilities, compressors and office equipment. Under ASC 842, a contract isefforts by creditors to collect on or contains a lease when (i)otherwise exercise rights or remedies with respect to pre-petition claims. Absent an order from the contract contains an explicitly or implicitly identified asset and (ii) the customer obtainsBankruptcy Court, substantially all of the economic benefits fromDebtors’ pre-petition liabilities are subject to settlement under the use of that underlying assetBankruptcy Code.
Executory Contracts
Subject to certain exceptions, under the Bankruptcy Code, the Debtors may assume, assign, or reject certain executory contracts and directs how and for what purposeunexpired leases subject to the asset is used during the termapproval of the Bankruptcy Court and certain other conditions. Generally, the rejection of an executory contract in exchange for consideration. The Company assesses whether an arrangementor unexpired lease is or contains a lease at inception of the contract. All leases (operating leases), other than those that qualify for the short-term recognition exemption, are recognized as of the lease commencement date on the balance sheettreated as a liability for its obligation related to thepre-petition breach of such executory contract or unexpired lease and, subject to certain exceptions, relieves the Debtors from performing their future obligations under such executory contract or unexpired lease but entitles the contract counterparty or lessor to a corresponding asset representing its rightpre-petition general unsecured claim for damages caused by such deemed breach. Generally, the assumption of an executory contract or unexpired lease requires the Debtors to use the underlying asset over the periodcure existing monetary defaults under such executory contract or unexpired lease and provide adequate assurance of use.future performance.
Potential Claims
The Company's leasesDebtors have remaining terms up to nine years. Certain of our lease agreements contain options to extend or early terminatefiled with the agreement. The lease term used to calculateBankruptcy Court schedules and statements setting forth, among other things, the lease asset and liability at commencement includes options to extend or terminate the lease when it is reasonably certain that we will exercise that option. When determining whether it is reasonably certain that the Company will exercise an option at commencement, it considers various economic factors, including capital expenditure strategies, the nature, length, and underlying terms of the agreement, as well as the uncertainty of the condition of leased equipment at the end of the lease term. Based on these determinations, the Company generally determines that the exercise of renewal options would not be reasonably certain in determining the expected lease term for leases, other than certain operating compressor leases.
The discount rate used to calculate the present value of the future minimum lease payments is the rate implicit in the lease, when readily determinable. As the Company's leases generally do not provide an implicit rate, the Company uses its incremental borrowing rate based on its revolving credit facility, which includes consideration of the nature, term, and geographic location of the leased asset.
Certain of the Company's leases include variable lease payments, including payments that depend on an index or rate, as well as variable payments for items such as property taxes, insurance, maintenance, and other operating expenses associated with leased assets. Payments that vary based on an index or rate are included in the measurement of the Company's lease assets and liabilities at the rate asof each of the commencement date. All other variable lease paymentsDebtors, subject to the assumptions filed in connection therewith. These schedules and statements may be subject to further amendment or modification after filing. Certain holders of pre-petition claims that are excluded fromnot governmental units are required to file proofs of claim by the measurementbar date of August 14, 2020. As of August 5, 2020, the Company's lease assets andDebtors' have received approximately 344 proofs of claim, primarily representing general unsecured claims, for an amount of approximately $77.5 million. These claims will be reconciled to amounts recorded in liabilities and are recognized in the period in which the obligation for those payments is incurred. The Company's lease agreements do not contain any material residual value guarantees or material restrictive covenants.
The Company has elected, for all classes of underlying assets,subject to not apply the balance sheet recognition requirements of ASC 842 to leases with a term of one year or less, and instead, recognize the lease paymentscompromise in the condensed consolidated statementsbalance sheet. Differences in amounts recorded and claims filed by creditors will be investigated and resolved, including through the filing of operations on a straight-line basis overobjections with the lease term.Bankruptcy Court, where appropriate. The Company has also mademay ask the election,Bankruptcy Court to disallow claims that the Company believes are duplicative, have been later amended or superseded, are without merit, are overstated or should be disallowed for its certain drilling equipment, completions equipment, equipment ancillary to drilling and completions, compressors and office equipment classes of underlying assets, to account for lease and non-lease components in a contractother reasons. In addition, as a single lease component.result of this process, the Company may identify additional liabilities that will need to be recorded or reclassified to liabilities subject to compromise. In light of the substantial number of claims filed, and expected to be filed, the claims resolution process may take considerable time to complete and likely will continue after the Debtors emerge from bankruptcy.
For the three and nine months ended September 30, 2019, lease costs, which represent the straight-line lease expenseFinancial Statement Classification of right-of-use ("ROU") assets and short-term leases, were as follows (in thousands):Liabilities Subject to Compromise
| | | | | | | | | | | |
| Three Months Ended September 30, 2019 | | Nine Months Ended September 30, 2019 |
| Lease Costs included in the Condensed Consolidated Balance Sheets | | | |
Proved oil and gas properties, including drilling, completions and ancillary equipment, and gathering systems and facilities (1) | $ | 92,023 | | | $ | 230,940 | |
| | | |
| Lease Costs included in the Condensed Consolidated Statements of Operations | | | |
Operating lease costs (2) | $ | 9,210 | | | $ | 22,627 | |
General and administrative expenses (3) | $ | 1,054 | | | $ | 2,811 | |
| Total operating lease costs | $ | 10,264 | | | $ | 25,438 | |
| | | |
| Total lease costs | $ | 102,287 | | | $ | 256,378 | |
(1) Represents short-term lease capital expenditures relatedThe accompanying condensed consolidated balance sheets as of June 30, 2020 includes amounts classified as liabilities subject to drilling rigs, completions equipmentcompromise, which represent liabilities the Company anticipates will be allowed as claims in the Chapter 11 Cases. These amounts represent the Debtors’ current estimate of known or potential obligations to be resolved in connection with the Chapter 11 Cases, and other equipment ancillarymay differ from actual future settlement amounts paid. Differences between liabilities estimated and claims filed, or to be filed, will be investigated and resolved in connection with the drillingclaims resolution process. The Company will continue to evaluate these liabilities throughout the chapter 11 process and completion of wells.
adjust amounts as necessary. Such adjustments may be material. Please refer to Note 4—Liabilities Subject to Compromise for more information.
(2) Includes $2.3 millionReorganization Items, Net
The Debtors, have incurred and $6.5 million of lease costs and $0.3 million and $0.5 million of variablewill continue to incur significant costs associated with operating leasesthe reorganization, primarily legal and professional fees. The amount of these costs, which since the Petition Date, are being expensed as incurred, are expected to significantly affect the Company’s results of operations. In accordance with applicable guidance, costs associated with the bankruptcy proceedings have been recorded as reorganization items within the Company's accompanying condensed consolidated statements of operations for the three and ninesix months ended SeptemberJune 30, 2019, respectively.2020. Please refer to Note 5—Reorganization Items, Net for more information.
(3) Includes $0.3
Revenue — Contract Balances
The Company had a certain revenue contract with an initial term beginning on November 1, 2016 and continuing until October 31, 2020 after which the contract began an automatic month-to-month renewal unless terminated by either party giving notice at least 180 days prior to the effective termination date but in no event could either party give such notice earlier than November 1, 2020. Based on the accounting treatment pursuant to ASC 606 — Revenue from Contracts with Customers, the contract term would end on April 30, 2021 because it could be terminated by either party with no penalty effective as of such date. The contract term impacted the amount of consideration that could be included in the transaction price. The Company recognizes revenue and invoices customers once its performance obligations have been satisfied. When it becomes probable that the Company will not meet its performance obligations, the transaction price allocated to the performance obligation is constrained in the amount of the estimated unmet performance obligation and recognized as a reduction to revenue in the period in which the transaction price changes. For the three and six months ended June 30, 2020, $3.9 million and $1.1$12.3 million, respectively, were recorded as a reduction in the transaction price resulting from unsatisfied performance obligations in the period. On June 12, 2020, the Company and the counterparty to the contract mutually cancelled the contract effective June 30, 2020. As a result of lease coststhe contract termination, the Company incurred an early termination fee of $9.5 million recorded in accounts payable and $0.4accrued liabilities and other operating expenses, though the amount is under review and may be disputed. The remaining performance obligation of $42.3 million recorded in other non-current liabilities, $12.1 million recorded in inventory, prepaid expenses and other and $0.9 million recorded in other non-current assets, were extinguished upon termination of the contract on June 30, 2020 and written down to zero. The Company also recorded a liability of $35.7 million in accounts payable and accrued liabilities representative of cash received in excess of barrels delivered through June 30, 2020 and owed to the counterparty upon termination.
Other Operating Expenses
Other operating expenses were $13.2 million and $1.0$65.8 million of variable costs associated with operating leases, as well as $0.1 million and $0.2 million of sublease income for the three and ninesix months ended SeptemberJune 30, 2019,2020, respectively. There were no other operating expenses for the three and six months ended June 30, 2019. The amounts in the current year are made up of the following:
Supplemental cash flow information related•$46.8 million loss contingency from an alleged breach in contract stemming from a purported failure to operating leases complete the pipeline extensions connecting certain wells to the Badger central gathering facility prior to April 1, 2020. Please see Note 14—Commitments and Contingencies for the nine months ended September 30, 2019, was as follows (in thousands):
| | | | | |
| Nine Months Ended September 30, 2019further details. |
Cash paid for amounts included in the measurements of lease liabilities | |
Operating cash flows from operating leases | $ | (9,014) | |
Right-of-use assets obtained in exchange for lease obligations | |
Operating leases | $ | (2,997) | |
Supplemental balance sheet information related to operating and finance leases as of September 30, 2019, were as follows (in thousands, except lease term and discount rate):
| | | | | | | | | | | |
| Classification•$9.5 million early termination penalty for the revenue contract terminated in June 2020. Please see the section Revenue — Contract Balance immediately above for further details. | | As of September 30, 2019 |
Operating Leases | | | |
Operating lease right-of-use assets | Other non-current assets | | $ | 20,470 | |
Operating lease obligation - short-term | Accounts payable and accrued liabilities | | 9,236 | |
Operating lease obligation - long-term | Other non-current liabilities | | 16,827 | |
Total operating lease liabilities | | | $ | 26,063 | |
| | | |
Weighted Average Remaining Lease Term in Years | | | |
Operating leases | | | 5.8 |
Weighted Average Discount Rate | | | |
Operating leases | | | 4.7 | % |
As of September 30, 2019, the Company was subject•$7.1 million charge to commitments on 1 drilling rig contracted through November 2019. These costs are capitalized within proved oilincome for expenses related to a workforce reductions in February 2020 and gas properties on the condensed consolidated balance sheets and are included as short-term lease costs. Beginning in November 2019, the Company will be subject to commitments on one drilling rig contracted through February 2021. As of September 30, 2019, the Company had an insignificant amount of additional operating leases that have not yet commenced, of which none included involvement with the construction or design of the underlying asset.May 2020.
Recent Accounting Pronouncements
In February 2016, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2016-02—Leases (Topic 842), which requires lessee recognition on the balance sheet of a right of use asset and a lease liability, initially measured at the present value of the lease payments. It further requires recognition in the$2.4 million charge to income statement of a single lease cost, calculated so that the cost of the lease is allocated over the lease term on a generally straight-line basis. Finally, it requires classification of all cash payments within operating activities in the statements of cash flows. It is effective for fiscal years commencing after December 15, 2018. The FASB subsequently issued ASU No. 2017-13, ASU No. 2018-01, ASU No. 2018-10, ASU No. 2018-11 and ASU No. 2019-01, which provided additional implementation guidance. The Company adopted the accounting standard using a modified retrospective transition approach, which applies the provisions of the new guidance at the effective date without adjusting the comparative periods presented. The Company has elected the package of practical expedients permitted under the transition guidance with the new standard, which among other things, requires no reassessment of whether existing contracts are or contain leases as well as no reassessment of lease classification for existing leases upon adoption. The Company has also elected the optional practical expedient permitted under the transition guidance within the new standardexpenses related to land easements that allows it to carry forward its current accounting treatment for land easements on existing agreements upon adoption. The Company made an accounting policy election to keep leases with an initial termcertain drilling rig standby charges during the second quarter of twelve months or less off of the condensed consolidated balance sheet.2020.
The adoptionImpairment of this guidance resulted inOil and Gas Properties
For the recognition of right-of-use ("ROU") assets of approximately $26.3three and six months ended June 30, 2020, the Company recognized $0.8 million and current$1.6 million, respectively, of impairment expense on its proved oil and non-current lease liabilities for operating leasesgas properties related to impairment of approximately $10.1assets in its northern field. For the three and six months ended June 30, 2019, the Company recognized $3.0 million and $21.1$11.2 million, respectively, as of January 1,impairment expense on its proved oil and gas properties related to impairment of assets in its northern field. The fair value did not exceed the Company's carrying amount associated with its proved oil and gas properties in its northern field. For the three and six months ended June 30, 2020 and 2019, including immaterial reclassifications of prepaid rent, deferred rent and lease incentive liability balances. The adoption of this guidancethe Company did not have a material impact toany proved property impairment in its Core DJ Basin field.
Of the Company's cash flows from operating, investing,$62.7 million in exploration and abandonment expenses for the three months ended June 30, 2020, $62.6 million was lease abandonment expense. Of the Company's $175.1 million in exploration and abandonment expenses for the six months ended June 30, 2020, $169.6 million was lease abandonment expense. Unproved oil and gas properties consist of costs to acquire unevaluated leases as well as costs to acquire unproved reserves. The Company evaluates significant unproved oil and gas properties for impairment based on remaining lease term, drilling results, reservoir performance, seismic interpretation or financing activities.future plans to develop acreage. When successful wells are drilled on undeveloped leaseholds, unproved property costs are reclassified to proved properties and depleted on a unit-of-production basis. Impairment expense and lease extension payments for unproved properties are reported in exploration and abandonment expenses in the condensed consolidated statements of operations.
Recent Accounting Pronouncements
In June 2016, the FASBFinancial Accounting Standards Board ("FASB") issued ASUAccounting Standards Update ("ASU") No. 2016-13, Financial Instruments—Credit Losses. In May 2019, ASU No. 2016-13 was subsequently amended by ASU No. 2019-04, Codification Improvements to Topic 326, Financial Instruments—Credit Losses and ASU No. 2019-05, Financial Instruments—Credit Losses (Topic 326): Targeted Transition Relief. ASU No. 2016-13, as amended, affects trade receivables, financial assets and certain other instruments that are not measured at fair value through net income. This ASU will replacereplaced the currently required incurred loss approach with an expected loss model for instruments measured at amortized cost and iswas effective for financial statements issued for fiscal years beginning after December 15, 2019, including interim periods within those fiscal years. ASU No. 2016-13 will be applied using a modified retrospective approach through a cumulative-effect adjustment to retained earnings as of the beginning of the first reporting period in which the guidance is effective. The Company does not believeadopted this ASU on January 1, 2020, and the adoption of this ASU willdid not have a material impact on the Company’s consolidated financial statements as the Company does not have a history of material credit losses.and related disclosures.
In August 2018, the FASB issued Accounting Standards Update ASU No. 2018-13, which improves the disclosure requirements onremoves or modifies current fair value measurements.disclosures and adds additional disclosures. The update to the guidance is the result of the FASB's test of the principles developed in its disclosure effectiveness project, which is designed to improve the effectiveness of disclosures in the notes to the financial statements. The disclosures that have been removed or modified may be applied immediately with retrospective application. For public entities, the new guidance was effective for fiscal years beginning after December 15, 2019, including interim reporting periods within that reporting period. The Company adopted this ASU on January 1, 2020, and the adoption did not have a material impact on the consolidated financial statements and related disclosures.
In August 2018, the FASB issued ASU No. 2018-15, which aligns the requirements for capitalizing implementation costs incurred in a hosting arrangement that is a service contract with the requirements for capitalizing implementation costs incurred to develop or obtain internal-use software and hosting arrangements that include an internal-use software license. For public entities, the guidance is effective for fiscal years beginning after December 15, 2019, including interim reporting periods within that reporting period. The Company is currently evaluatingadopted this new standard to determineASU on January 1, 2020 which did not have a material impact on the potential impact to itsconsolidated financial statements and related disclosures.disclosures as capitalized costs for internal-use software were not material as of June 30, 2020.
Other than as disclosed above or in the Company’s Annual Report, there are no other accounting standards applicable to the Company as of June 30, 2020 and through the date of this filing that would have a material effect on the Company’s unaudited condensed consolidated financial statements and related disclosures that have been issued but not yet adopted by the Company through the date of this filing.Company.
Note 3—Acquisitions and Divestitures
February 2020 Divestiture
In February 2020, the Company completed the sale of certain non-operated producing properties for aggregate sales proceeds of approximately $12.2 million, subject to customary purchase price adjustments. No gain or loss was recognized for the February 2020 Divestiture. The Company continues to explore divestitures as part of our ongoing initiative to divest non-strategic assets.
December 2019 Divestiture
In December 2019, the Company completed the sale of certain non-operated producing properties for aggregate sales proceeds of approximately $10.0 million, subject to customary purchase price adjustments. No gain or loss was recognized for the December 2019 Divestiture.
August 2019 Divestiture
OnIn August 22, 2019, the Company completed the sale of certain non-operated producing properties for aggregate sales proceeds of approximately $22.0 million, subject to customary purchase price adjustments. No gain or loss was recognized for the August 2019 Divestiture. The Company continues to explore divestitures, as part of our ongoing initiative to divest of non-strategic assets.
March 2019 Divestiture
OnIn March 27, 2019, the Company completed the sale of its interests in approximately 5,000 net acres of leasehold and producing properties for aggregate sales proceeds of approximately $22.4 million. The effective date for the March 2019 Divestiture was July 1, 2018 with purchase price adjustments calculated as of the closing date of $5.9 million, resulting in net proceeds of $16.5 million. No gain or loss was recognized for the March 2019 Divestiture.
December 2018 Divestitures
Note 4—Liabilities Subject to Compromise
In December 2018, the Company completed various sales of its interests in approximately 31,200 net acres of leasehold and primarily non-producing properties, for aggregate sales proceeds of approximately $8.5 million,The Company’s liabilities subject to customary purchase price adjustments, and recognized a losscompromise consisted of $6.1 million for the year ended December 31, 2018.following (in thousands):
August 2018 Divestiture | | | | | |
| June 30,
2020 |
| Accounts payable and accrued liabilities | $ | 126,729 | |
| Revenue payable | 85,417 | |
| Production taxes payable - current | 168,380 | |
| Production taxes payable - non-current | 21,149 | |
| Asset retirement obligations - current | 12,832 | |
| Asset retirement obligations - non-current | 77,361 | |
| Accrued interest on debt subject to compromise | 32,045 | |
| 2024 Senior Notes due May 15, 2024 | 400,000 | |
| 2026 Senior Notes due February 1, 2026 | 700,189 | |
| Deferred liability | 16,528 | |
| Deferred tax liability | 2,200 | |
| Rejected contracts | 7,734 | |
| Other non-current liabilities | 46,777 | |
| Total liabilities subject to compromise | $ | 1,697,341 | |
As discussed in Note 1—Business and Organization — Voluntary Reorganization under Chapter 11 of the Bankruptcy Code, since the Petition Date, the Company has been operating as debtor-in-possession under the jurisdiction of the Bankruptcy Court and in accordance with provisions of the Bankruptcy Code. On August 3, 2018, Elevation received proceeds of $83.6 million and recognized a gain of $83.6 million for the year ended December 31, 2018, upon the sale of assets of DJ Holdings, LLC, a subsidiary of Discovery Midstream Partners, LP, of which Elevation held a 10% membership interest. The Company acquired its interest in exchange for the contribution of an acreage dedication, which is considered a nonfinancial asset.
April 2018 Divestitures
In April 2018,balance sheets, the line item liabilities subject to compromise reflects the expected allowed amount of the prepetition claims that are not fully secured and that have at least a possibility of not being repaid at the full claim amount. Determination of the value at which liabilities will ultimately be settled cannot be made until the Bankruptcy Court approves the Restructuring Plan. The Company completed various saleswill continue to evaluate the amount and classification of its interests in approximately 15,100 net acresprepetition liabilities. Any additional liabilities that are subject to compromise will be recognized accordingly, and the aggregate amount of leasehold and primarily non-producing properties for aggregate sales proceeds of approximately $72.3 million and recognized a gain of $59.3 million for the year ended December 31, 2018.
April 2018 Acquisition
On April 19, 2018, the Company acquired an unaffiliated oil and gas company's interest in approximately 1,000 net acres of non-producing leasehold primarily located in Arapahoe County, Colorado. Upon closing the seller received approximately $9.4 million in cash. This transaction has been accounted for as an asset acquisition. The acquisition provided new development opportunities in the Core DJ Basin.
January 2018 Acquisition
On January 8, 2018, the Company acquired an unaffiliated oil and gas company's interest in approximately 1,200 net acres of non-producing leasehold located in Arapahoe County, Colorado. Upon closing the seller received approximately $11.6 million in cash. This transaction has been accounted for as an asset acquisition. The acquisition provided new development opportunities in the Core DJ Basin.
Note 4—Long-Term Debt5— Reorganization Items, Net
The Company’s reorganization items, net consisted of the following (in thousands):
| | | | | |
| For the Three and Six Months Ending |
| June 30,
2020 |
| Professional fees | $ | 2,350 | |
| Professional services fees | 2,200 | |
| Trustee fees | 115 | |
| Damages for rejected contracts | 7,734 | |
| DIP Credit Facility fees | 1,251 | |
| Write-off of debt issuance costs | 13,269 | |
| Total reorganization items, net | $ | 26,919 | |
As of June 30, 2020, $9.9 million of reorganization costs, net consisting of professional fees, trustee fees and damages for rejected contracts are accrued and unpaid and are presented in either accounts payable and accrued liabilities or liabilities subject to compromise on the dates indicated,condensed consolidated balance sheets. The write-off of the Senior Notes' debt issuance costs are included in reorganization items, net as the Company believes the underlying debt instruments will be impacted by the Chapter 11 Cases. The write-off of the Senior Notes debt issuance costs is a non-cash reorganization item. For the three and six months ended June 30, 2020, the Company had cash charges related to reorganization items, net of $3.8 million.
Note 6—Long-Term Debt
The Company’s long-term debt consisted of the following (in thousands):
| | | | | | | | | | | |
| June 30,
2020 | | December 31,
2019 |
| DIP Credit Facility | $ | 37,500 | | | $ | — | |
| Credit Facility due August 16, 2022 (or an earlier time as set forth in the Credit Facility) | 481,935 | | | 470,000 | |
| 2024 Senior Notes due May 15, 2024 | 400,000 | | | 400,000 | |
| 2026 Senior Notes due February 1, 2026 | 700,189 | | | 700,189 | |
| Total principal | 1,619,624 | | | 1,570,189 | |
Unamortized debt issuance costs on Senior Notes (1) | — | | | (14,412) | |
| Total debt, prior to reclassification to liabilities subject to compromise | 1,619,624 | | | 1,555,777 | |
Less amounts reclassified to liabilities subject to compromise (2) | (1,100,189) | | | — | |
Total debt not subject to compromise (3) | 519,435 | | | 1,555,777 | |
Less current portion of long-term debt (4) | (519,435) | | | — | |
| Total long-term debt | $ | — | | | $ | 1,555,777 | |
(1) As a result of the Chapter 11 Cases and the adoption of ASC 852, the Company wrote off all unamortized debt issuance cost balances to reorganization items, net in the condensed consolidated statements of operations for the three and six months ended June 30, 2020.
(2) Debt subject to compromise includes the principal balances of the Company’s Senior Notes, which are unsecured claims in the Chapter 11 Cases and where the payments are stayed.
(3) Debt not subject to compromise includes all borrowings outstanding under the Credit Facility and DIP Credit Facility which are fully secured claims in the Chapter 11 Cases and are expected to be unimpaired.
(4) Due to uncertainties regarding the outcome of the Chapter 11 Cases, the Company has classified the borrowings outstanding under the Credit Facility and DIP Credit Facility as current liabilities on the condensed consolidated balance sheets as of June 30, 2020.
| | | | | | | | | | | |
| September 30,
2019 | | December 31,
2018 |
| Credit facility due August 16, 2022 (or an earlier time as set forth in the credit facility) | $ | 550,000 | | | $ | 285,000 | |
| | | |
| 2024 Senior Notes due May 15, 2024 | 400,000 | | | 400,000 | |
| 2026 Senior Notes due February 1, 2026 | 700,189 | | | 750,000 | |
| Unamortized debt issuance costs on Senior Notes | (14,972) | | | (17,341) | |
| Total long-term debt | 1,635,217 | | | 1,417,659 | |
| Less: current portion of long-term debt | — | | | — | |
| Total long-term debt, net of current portion | $ | 1,635,217 | | | $ | 1,417,659 | |
Chapter 11 Cases and Effect of Automatic Stay
On June 14, 2020, the Company filed for relief under Chapter 11 of the Bankruptcy Code. The commencement of a voluntary proceeding in bankruptcy constituted an immediate event of default under the Credit Agreement and the indentures governing the Company’s Senior Notes, resulting in the automatic and immediate acceleration of all of the Company’s outstanding debt under the Credit Agreement and Senior Notes. In conjunction with the filing of the Chapter 11 Cases, the Company did not make the $14.8 million interest payment on the Company’s 2024 Senior Notes (as defined below) due on May 15, 2020. Any efforts to enforce payment obligations related to the acceleration of the Company’s debt have been automatically stayed as a result of the filing of the Chapter 11 Cases, and the creditors’ rights of enforcement are subject to the applicable provisions of the Bankruptcy Code. Please refer to Note 1—Business and Organization — Ability to Continue as a Going Concern for more information on the Chapter 11 Cases.
Debtor-in-Possession Financing
On June 16, 2020, in connection with the filing of the Chapter 11 Cases, the Debtors entered into a debtor-in-possession credit agreement on the terms set forth in a Superpriority Senior Secured Debtor-in-Possession Credit Agreement (the “DIP Credit Agreement”), by and among the Company, as borrower, the Company’s subsidiaries party thereto, as guarantors, the lenders party thereto (the “DIP Lenders”), and Wells Fargo Bank, National Association, as DIP agent and issuing lender, pursuant to which, having been granted the approval of the Bankruptcy Court, the DIP Lenders agree to provide the Company with a superpriority senior secured debtor-in-possession credit facility (as amended, the “DIP Credit Facility”) with loans in an aggregate principal amount not to exceed $50.0 million that, among other things, will be used to finance the ongoing general corporate needs of the Debtors during the course of the Chapter 11 Cases. In addition to the $50.0 million of incremental loans, the DIP Credit Facility contemplates $75.0 million in Credit Facility loans to be rolled over into the DIP Credit Facility, for a total facility size of $125.0 million.
The maturity date of the DIP Credit Agreement is the earliest of (i) December 14, 2020, or the date that is six (6) months after the filing of the Chapter 11 Cases; provided, that such date may be extended to March 14, 2021 with the prior written approval of certain of the DIP Lenders; (ii) the consummation of a sale of all or substantially all of the assets of the Debtors; (iii) the effective date of a plan of reorganization or liquidation in the Chapter 11 Cases; (iv) the entry of an order by the Bankruptcy Court dismissing any of the Chapter 11 Cases or converting such Chapter 11 Cases to a case under chapter 7 of title 11 of the United States Bankruptcy Code; and (v) the date of termination of the DIP Lenders’ commitments and the acceleration of any outstanding extensions of credit, in each case, under the DIP Credit Agreement and in accordance with the interim and final orders entered by the Bankruptcy Court concerning the DIP Credit Agreement. Furthermore, the DIP Credit Facility's interest rate varies similar to the Company's Credit Agreement and was a LIBOR loan with a base interest rate of 1.00% and spread of 5.75% as of June 30, 2020.
The DIP Credit Agreement contains a requirement that the Company provide, on a monthly basis, a rolling thirteen-week operating budget and cash flow forecast (the “Approved Budget”) and not vary from the Approved Budget, subject to a Permitted Variance (defined below). The Approved Budget is, subject to certain exceptions, tested on a weekly basis to measure any variance, on an aggregate basis, for all disbursements made in the prior four-week period. The disbursements actually made in such prior four week period compared to the budgeted aggregate disbursements for such four week period reflected in the most recently delivered Approved Budget may not vary by more than 10% (or a greater amount, to the extent agreed upon by the DIP Agent) (such variance, a “Permitted Variance”). As of June 30, 2020, the Company was in compliance with the covenants under the DIP Credit Facility.
The DIP Credit Agreement contains events of default customary to debtor-in-possession financings, including events related to the Chapter 11 Cases, the occurrence of which could result in the acceleration of the Debtors’ obligation to repay the outstanding indebtedness under the DIP Credit Agreement. The Debtors’ obligations under the DIP Credit Agreement will be secured by a security interest in, and lien on, substantially all present and after acquired property (whether tangible, intangible, real, personal or mixed) of the Debtors and will be guaranteed by all of the Company’s restricted subsidiaries.
On July 20, 2020, the Company, together with its subsidiaries party thereto, certain of the DIP Lenders and Wells Fargo Bank, National Association entered into an amendment to the DIP Credit Agreement (“Amendment No. 1”) to, among other things: (i) extend certain Milestones in the DIP Credit Agreement, (ii) modify the limitation on the amount of undrawn New Money Interim Loans and New Money Final Loans in any borrowing so that the amount
permitted to be drawn in accordance with the Approved Budget gives effect to the Permitted Variance, (iii) provide for customary prohibitions against unreasonable withholding of approvals with respect to the Approved Budget and the Restructuring Plan on the part of the DIP Lenders and the DIP Agent, and (iv) reaffirm the Debtors’ liens, guaranties and representations and warranties under the DIP Credit Agreement.
As of June 30, 2020, the Company's DIP Credit Facility borrowings were $15.0 million and $22.5 million had been rolled over from the Credit Facility for a total outstanding balance of $37.5 million. The DIP Credit Facility is classified as a current liability on the condensed consolidated balance sheets as of June 30, 2020 as it is fully secured and expected to be unimpaired. On July 20, 2020 the Bankruptcy Court entered the final order approving the DIP Credit Agreement and associated DIP Credit Facility (the “Final DIP Order”) and $52.5 million was rolled over from the Credit Agreement into the DIP Credit Facility. As of July 20, 2020, the DIP Credit Facility had $35.0 million of undrawn availability. On July 27, 2020, the Company drew an additional $20.0 million on the DIP Credit Facility leaving $15.0 million of availability on the facility. However, this availability could be restricted by a minimum liquidity covenant of $10.0 million from unrestricted cash and DIP Credit Facility availability.
Credit FacilityAgreement
In August 2017, the Company entered into an amendment and restatement of its existing credit facility (prior to amendment and restatement, the "Prior Credit Facility"), to provide aggregate commitments of $1.5 billion with a syndicate of banks, which is subject to a borrowing base.base (as amended, the "Credit Facility"). The credit facilityCredit Facility matures on the earlier of (a) August 16, 2022, (b) April 15, 2021, if (and only if) (i) the Series A Preferred Stock of the Company (the "Series A Preferred Stock") have not been converted into common equity or redeemed prior to April 15, 2021 (the Company can redeem the Series A Preferred Stock at any time), and (ii) prior to April 15, 2021, the maturity date of the Series A Preferred Stock has not been extended to a date that is no earlier than six months after August 16, 2022 or (c) the earlier termination in whole of the commitments.commitments under the Credit Facility. No principal payments are generally required until the credit agreementCredit Facility matures or in the event that the borrowing base falls below the outstanding balance.
In January 2019, the Company amended its revolving credit facility to permit prepayments and redemptions of its unsecured bonds, subject to certain term, conditions and financial thresholds.
In June 2019, the Company amended its revolving credit facility to (i) increase the elected commitments from $650.0 million to $900.0 million, (ii) increase the amount for permitted letters of credit from $50.0 million to $100.0 million and increase in the letter of credit for the Company's oil marketer from $35.0 million to $40.0 million, (iii) decrease the borrowing base from $1.2 billion to $1.1 billion and (iv) increase the limitation on permitted investments from $15.0 million to $20.0 million.
In August 2019, the Company amended its revolving credit facility to increase the elected commitments from $900.0 million to $1.0 billion.
As of September 30, 2019, the credit facility was subject to a borrowing base of $1.1 billion, subject to current elected commitments of $1.0 billion. As of September 30, 2019 and December 31, 2018, the Company had outstanding borrowings of $550.0 million and $285.0 million, respectively, and had standby letters of credit of $49.4 million and $35.7 million, respectively, which reduces the availability of the undrawn borrowing base. At September 30, 2019, the undrawn balance under the credit facility was $450.0 million before letters of credit. This undrawn balance may be constrained by the Company's quantitative covenants under the credit facility, including the current ratio and ratio of consolidated debt less cash balances to its consolidated EBITDAX, at the next required quarterly compliance date. As of November 8, 2019, the Company had $550.0 million in borrowings outstanding under the credit facility.
On November 4, 2019, the Company amended its revolving credit facility to decrease the borrowing base from $1.1 billion to $950.0 million, associated with the scheduled borrowing base redetermination. The current elected commitments were also decreased to $950.0 million.
The amount available to be borrowed under the Company's revolving credit facilityCompany’s Credit Facility is subject to a borrowing base that is redetermined semiannually on each May 1 and November 1, and will depend on the volumes of the Company'sCompany’s proved oil and gas reserves, andcommodity prices, estimated cash flows from these reserves and other information deemed relevant by the administrative agent under the Company’s Credit Facility. Additionally, the undrawn balance may be constrained by the Company's revolvingquantitative covenants under the Credit Facility, including the current ratio and ratio of consolidated debt less cash balances to its consolidated EBITDAX, at the next required quarterly compliance date.
On April 27, 2020, the lenders under the Credit Facility provided notice to the Company that they had completed the redetermination scheduled to occur on May 1, 2020, and via this redetermination, the borrowing base had been reduced from $950.0 million to $650.0 million. Following this redetermination, the Company had outstanding borrowings of $600.5 million and had standby letters of credit of $49.5 million, which reduce the availability of the undrawn borrowing base.
The commencement of the Chapter 11 Cases constituted a termination event with respect to the Company’s derivative instruments, which permits the counterparties to such derivative instruments to terminate their outstanding hedges. Such termination events are not stayed under the Bankruptcy Code. During June 2020, certain of the lenders under the Credit Agreement elected to terminate their International Swaps and Derivatives Association master agreements and outstanding hedges with the Company for aggregate settlement proceeds of $96.1 million. The proceeds from these terminations were applied to the outstanding borrowings under the Credit Facility.
As is described in the Debtor-in-Possession Financing section above, $22.5 million rolled from the Credit Facility to the DIP Credit Facility on June 16, 2020 and an additional $52.5 million rolled on July 20, 2020 upon court approval of the Final DIP Order. As of June 30, 2020, the Credit Facility had a drawn balance of $481.9 million classified as a current liability on the condensed consolidated balance sheet. As of the date of this filing, the available balance under the Credit Facility was 0.
Principal amounts borrowed on the Credit Facility will be payable on the maturity date. The Company can repay any amounts borrowed prior to the maturity date without any premium or penalty other than customary LIBOR breakage costs. Prior to the filing of the Chapter 11 Cases, amounts repaid under the Credit Facility could be re-borrowed from time to time, subject to the terms of the facility.
Interest on the credit facilityCredit Facility is payable at one of the following two variable rates as selected by the Company: a base rate based on the Prime Rate or the Eurodollar rate, based on LIBOR. Either rate is adjusted upward by an applicable margin, based on the utilization percentage of the facility as outlined in the pricing grid below. Additionally, the credit facilityCredit Facility provides for a commitment fee of 0.375% to 0.50%, depending on borrowing base usage. Due to the bankruptcy filing on June 14, 2020, a default penalty of an additional 2.00% went into effect and increased the Credit Agreement interest rates above those interest rates shown in the grid below. The grid below shows the Base Rate Margin and Eurodollar Margin depending on the applicable Borrowing Base Utilization Percentage (as defined in the credit facility)Credit Agreement) as of the date of this filing:
Borrowing Base Utilization Grid
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Eurodollar | | Base Rate | | Commitment |
| Borrowing Base Utilization Percentage | Borrowing Base Utilization Percentage | | Utilization | | Eurodollar
Margin | | Base Rate
Margin | | Commitment
Fee Rate | Borrowing Base Utilization Percentage | | Utilization | | | Margin | | Margin | | Fee Rate |
| Level 1 | Level 1 | | < 25% | | 1.50 | % | | 0.50 | % | | 0.375 | % | Level 1 | | <25% | | | 1.50 | % | | 0.50 | % | | 0.38 | % |
| Level 2 | Level 2 | | ≥ 25% < 50% | | 1.75 | % | | 0.75 | % | | 0.375 | % | Level 2 | | ≥ | 25% | < | 50% | | 1.75 | % | | 0.75 | % | | 0.38 | % |
| Level 3 | Level 3 | | ≥ 50% < 75% | | 2.00 | % | | 1.00 | % | | 0.500 | % | Level 3 | | ≥ | 50% | < | 75% | | 2.00 | % | | 1.00 | % | | 0.50 | % |
| Level 4 | Level 4 | | ≥ 75% < 90% | | 2.25 | % | | 1.25 | % | | 0.500 | % | Level 4 | | ≥ | 75% | < | 90% | | 2.25 | % | | 1.25 | % | | 0.50 | % |
| Level 5 | Level 5 | | ≥ 90% | | 2.50 | % | | 1.50 | % | | 0.500 | % | Level 5 | | ≥90% | | | 2.50 | % | | 1.50 | % | | 0.50 | % |
The credit facilityCredit Agreement contains representations, warranties, covenants, conditions and defaults customary for transactions of this type, including but not limited to: (i) limitations on liens and incurrence of debt covenants; (ii) limitations on dividends, distributions, redemptions and restricted payments covenants; (iii) limitations on investments, loans and advances covenants; and (iv) limitations on the sale of property, mergers, consolidations and other similar transactions covenants. Additionally, the credit facilityCredit Agreement limits the Company entering into hedges in excess of 85% of its anticipated production volumes.
The credit facilityCredit Agreement also contains financial covenants requiring the Company to comply on the last day of each quarter with a current ratio of its restricted subsidiaries’ current assets (includes availability under the revolving credit facilityCredit Facility and unrestricted cash and excludes derivative assets) to its restricted subsidiaries’ current liabilities (excludes obligations under the revolving credit facility,Credit Facility, senior notes and certain derivative liabilities), of not less than 1.0 to 1.0 and to maintain, on the last day of each quarter, a ratio of its restricted subsidiaries’ debt less cash balances to its restricted subsidiaries EBITDAX (EBITDAX is defined as net income adjusted for interest expense, income tax expense/benefit, DD&A, exploration and abandonment expenses as well as certain non-recurring cash and non-cash charges and income (such as stock-based compensation expense, unrealized gains/losses on commodity derivatives and impairment of long-lived assets)assets and goodwill), subject to pro forma adjustments for non-ordinary course acquisitions and divestitures) for the 4four fiscal quarter periodperiods most recently ended, of not greater than 4.0:1.0. 4.0 to 1.0 as of the last day of such fiscal quarter.
The Company was in compliance with all financial covenantsacceleration of the obligations under the credit facilityCredit Agreement as of SeptemberJune 14, 2020 resulted in a cross-default and acceleration of the maturity of the Company’s other outstanding long-term debt. The Credit Facility is classified as a current liability on the condensed consolidated balance sheets as of June 30, 20192020 as it is fully secured and through the filing of this report.expected to be unimpaired.
Any borrowings under the credit facilityCredit Facility are collateralized by substantially all of the assets of the Company and certain of its subsidiaries, including oil and gas properties, personal property and the equity interests of those subsidiaries.subsidiaries of the Company. The Company has entered into oil and natural gas hedging transactions with several counterparties that are also lenders under the credit facility.Credit Facility. The Company’s obligations under these hedging contracts are secured by the collateral securing the credit
facility.Credit Facility. Elevation is a separate entityan unrestricted subsidiary, which is no longer consolidated or controlled by the Company, and the assets and credit of Elevation are not available to satisfy the debts and other obligations of the Company or its other subsidiaries. As
2021 Senior Notes
In July 2016, the Company issued at par $550.0 million principal amount of 7.875% Senior Notes due July 15, 2021 (the “2021 Senior Notes” and the offering, the “2021 Senior Notes Offering”). The 2021 Senior Notes bore an annual interest rate of 7.875%. The interest on the 2021 Senior Notes was payable on January 15 and July 15 of each year commencing on January 15, 2017. The Company received net proceeds of approximately $537.2 million after deducting discounts and fees.
Concurrent with the 2026 Senior Notes Offering (as defined below), the Company commenced a cash tender offer to purchase any and all of its 2021 Senior Notes. On January 24, 2018, the Company received approximately $500.6 million aggregate principal amount of the 2021 Senior Notes which were validly tendered (and not validly withdrawn). As a result, on January 25, 2018, the Company made a cash payment of approximately $534.2 million, which includes a principal of approximately $500.6 million, a make-whole premium of approximately $32.6 million and accrued and unpaid interest of approximately $1.0 million.
On February 17, 2018, the Company redeemed approximately $49.4 million aggregate principal amount of the 2021 Senior Notes that remained outstanding after the Tender Offer and made a cash payment of approximately $52.7 million to the remaining holders of the 2021 Senior Notes, which included a make-whole premium of $3.0 million and accrued and unpaid interest of approximately $0.3 million.
2024 Senior Notes
In August 2017, the Company issued at par $400.0 million principal amount of 7.375% Senior Notes due May 15, 2024 (the “2024"2024 Senior Notes”Notes" and the offering, the “2024"2024 Senior Notes Offering”Offering"). The 2024 Senior Notes bear an annual interest rate of 7.375%. The interest on the 2024 Senior Notes is payable on May 15 and November 15 of each year which commenced on November 15, 2017. The Company received net proceeds of approximately $392.6 million after deducting fees.
The Company's 2024 Senior Notes are its senior unsecured obligations and rank equally in right of payment with all of its other senior indebtedness and senior to any of its subordinated indebtedness. The Company's 2024 Senior Notes are fully and unconditionally guaranteed on a senior unsecured basis by certain of the Company's current subsidiaries and by certain future restricted subsidiaries that guarantees its indebtedness under a credit facilityCredit Facility (the “2024"2024 Senior Note Guarantors”Notes Guarantors"). The notes2024 Senior Notes are effectively subordinated to all of the Company's secured indebtedness (including all borrowings and other obligations under its revolving credit facility)Credit Facility) to the extent of the value of the collateral securing such indebtedness, and structurally subordinated in right of payment to all existing and future indebtedness and other liabilities (including trade payables) of any of its future subsidiaries that do not guarantee the notes.2024 Senior Notes.
The 2024 Senior Notes also contain affirmative and negative covenants that, among other things, limit the Company's and the 2024 Senior Notes Guarantors' ability to make investments; declare or pay any dividend or make any other payment to holders of the Company’s or any of its 2024 Senior Notes Guarantors’ equity interests; repurchase or redeem any equity interests of the Company; repurchase or redeem subordinated indebtedness; incur additional indebtedness or issue preferred stock; create liens; sell assets; enter into agreements that restrict dividends or other payments by restricted subsidiaries; consolidate, merge or transfer all or substantially all of the assets of the Company; engage in transactions with the Company's affiliates; engage in any business other than the oil and gas business; and create unrestricted subsidiaries. The indenture governing the 2024 Senior Notes (the “2024 Senior Notes Indenture”) also contains customary events of default. Upon the occurrence of events of default arising from certain events of bankruptcy or insolvency, the 2024 Senior Notes shall become due and payable immediately without any declaration or other act of the trustee or the holders of the 2024 Senior Notes. Upon the occurrence of certain other events of default, the trustee or the holders of at least 25% in aggregate principal amount of the then outstanding 2024 Senior Notes may declare all outstanding 2024 Senior Notes to be due and payable immediately.
The filing of the Chapter 11 Cases resulted in an event of default under and acceleration of the maturity of the Company’s 2024 Senior Notes.
2026 Senior Notes
In January 2018, the Company issued at par $750.0 million principal amount of 5.625% Senior Notes due February 1, 2026 (the “2026"2026 Senior Notes”Notes" and together with the 2024 Senior Notes, the "Senior Notes" and the offering of the “20262026 Senior Notes, Offering”the "2026 Senior Notes Offering"). The 2026 Senior Notes bear an annual interest rate of 5.625%. The interest on the 2026 Senior Notes is payable on February 1 and August 1 of each year commencing on August 1, 2018. The Company received net proceeds of approximately $737.9 million after deducting fees. The Company used $534.2 million of the net proceeds from the 2026 Senior Notes Offering to fund the tender offer for its 2021 Senior Notes, $52.7 million to redeem any 2021 Senior Notes not tendered and the remainder for general corporate purposes.
The Company's 2026 Senior Notes are the Company's senior unsecured obligations and rank equally in right of payment with all of the Company's other senior indebtedness and senior to any of the Company's subordinated indebtedness. The Company's 2026 Senior Notes are fully and unconditionally guaranteed on a senior unsecured basis by certain of the Company's current subsidiaries and by certain future restricted subsidiaries that guarantee the Company's indebtedness under a credit facility.Credit Facility (the "2026 Senior Notes Guarantors"). The 2026 Senior Notes are effectively subordinated to all of the Company's secured indebtedness (including all borrowings and other obligations under the Company's revolving credit facility)its Credit Facility) to the extent of the value of the collateral securing such indebtedness, and structurally subordinated in right of payment to all existing and future indebtedness and other liabilities (including trade payables) of certain of the Company's future restricted subsidiaries that do not guarantee the 2026 Senior Notes.
The 2026 Senior Notes also contain affirmative and negative covenants that, among other things, limit the Company’sCompany's and the Guarantors’2026 Senior Notes Guarantors' ability to make investments; declare or pay any dividend or make any other payment to holders of the Company’sCompany's or any of its Guarantors’2026 Senior Notes Guarantors' equity interests; repurchase or redeem any equity interests of the Company; repurchase or redeem subordinated indebtedness; incur additional
indebtedness or issue preferred stock; create liens; sell assets; enter into agreements that restrict dividends or other payments by restricted subsidiaries; consolidate, merge or transfer all or substantially all of the assets of the Company; engage in transactions with the Company’s affiliates; engage in any business other than the oil and gas business; and create unrestricted subsidiaries. The indenture governing the 2026 Senior Notes (the “2026 Senior Notes Indenture”) also contains customary events of default. Upon the occurrence of events of default arising from certain events of bankruptcy or insolvency, the 2026 Senior Notes shall become due and payable immediately without any declaration or other act of the trustee or the holders of the 2026 Senior Notes. Upon
The filing of the occurrence of certain other eventsChapter 11 Cases resulted in an event of default the trustee or the holders of at least 25% in aggregate principal amountunder and acceleration of the then outstandingmaturity of the Company’s 2026 Senior Notes may declare all outstanding 2026 Senior Notes to be due and payable immediately.Notes.
Debt Issuance Costs
Debt issuance costs include origination, legal and other fees incurred in connection with the Company’s Credit Facility and Senior Notes. As of SeptemberJune 30, 2019,2020, the Company had debt issuance costs, net of accumulated amortization, of $3.9$0.9 million related to its credit facilityCredit Facility which has been reflected on the Company’sCompany's condensed consolidated balance sheetsheets within the line item other non-current assets. As a result of September 30, 2019,the bankruptcy, the Company hadwrote-off $13.3 million in unamortized debt issuance costs net of accumulated amortization, of $15.0 million related to itson the 2024 and 2026 Senior Notes (collectively,to reorganization items, net in the "Senior Notes") which has been reflected on the Company's balance sheet within the line item Senior Notes, netcondensed consolidated statements of unamortized debt issuance costs. Debt issuance costs include origination, legal, engineering and other fees incurred in connection with the Company’s credit facility and Senior Notes.operations. For the three and nine months ended SeptemberJune 30, 2020 and 2019, the Company recorded amortization expense related to the debt issuance costs of $1.0$1.9 million and $3.8$1.3 million, respectively, as comparedrespectively. For the six months ended June 30, 2020 and 2019, the Company recorded amortization expense related to $0.9the debt issuance costs of $3.2 million and $12.3$2.8 million, for the three and nine months ended September 30, 2018, respectively. Debt issuance costs for the nine months ended September 30, 2018 included $9.4 million of acceleration of amortization expense upon the repayment of the Company's 2021 Senior Notes. The repayment of the Company's 2021 Senior Notes had no impact to amortization expense for the three and nine months ended September 30, 2019 and the three months ended September 30, 2018.
Interest Incurred on Long-Term Debt
For the three and ninesix months ended SeptemberJune 30, 2019,2020, the Company incurred interest expense on long-term debt of $23.8$20.2 million and $66.9$42.5 million, respectively, as compared to $21.5$22.2 million and $61.6$43.0 million, respectively, for the three and ninesix months ended SeptemberJune 30, 2018,2019. Absent the automatic stay, interest expense for the three and six months ended June 30, 2020 would have been $23.2 million and $44.5 million, respectively. For the three and ninesix months ended SeptemberJune 30, 2019,2020, the Company capitalized interest expense on long term debt of $1.6$1.9 million and $5.4$4.0 million, respectively, as compared to $1.7$1.8 million and $6.3$3.8 million, respectively, for the three and ninesix months ended SeptemberJune 30, 2018, respectively,2019, which has been reflected in the Company’s condensed consolidated financial statements. Also included in interest expense for the nine months ended September 30, 2018 was a make-whole premium of $35.6 million related to the Company's repayment of its 2021 Senior Notes in January and February 2018. The repayment of the Company's 2021 Senior Notes had no impact to interest expense for the three and nine months ended September 30, 2019 and the three months ended September 30, 2018.
Senior Note Repurchase Program
On January 4, 2019, the Board of Directors authorized a program to repurchase up to $100.0 million of the Company’s Senior Notes.Notes (the “Senior Notes Repurchase Program”). The Company’s Senior Notes Repurchase Program is subject to restrictions under ourthe Credit Facility and does not obligate it to acquire any specific nominal amount of Senior Notes. For the three and six months ended SeptemberJune 30, 2019,2020, the Company did not repurchase 2026any Senior Notes. As a result of the Chapter 11 Cases, the authorization to repurchase Senior Notes is no longer applicable. For the ninethree and six months ended SeptemberJune 30, 2019, the Company repurchased 2026 Senior Notes with a nominal value of $14.0 million and $49.8 million, respectively, for $10.9 million and $39.3 million, respectively, in connection with the Senior Notes Repurchase Program. Interest expense for the ninethree and six months ended SeptemberJune 30, 2019 included a$3.1 million and $10.5 million of gain on debt repurchase, respectively, related to the Company's Senior NoteNotes Repurchase Program. The Senior Note Repurchase Program had no impact to interest expense for three and nine months ended September 30, 2018.
Note 5—7—Commodity Derivative Instruments
The Company has entered into commodity derivative instruments, as described below. The Company has utilized swaps, put options and call options to reduce the effect of price changes on a portion of the Company’s future oil and natural gas production.
A swap has an established fixed price. When the settlement price is below the fixed price, the counterparty pays the Company an amount equal to the difference between the settlement price and the fixed price multiplied by the hedged contract volume. When the settlement price is above the fixed price, the Company pays its counterparty an amount equal to the difference between the settlement price and the fixed price multiplied by the hedged contract volume.
A put option has an established floor price. The buyer of the put option pays the seller a premium to enter into the put option. When the settlement price is below the floor price, the seller pays the buyer an amount equal to the difference between the settlement price and the strike price multiplied by the hedged contract volume. When the settlement price is above the floor price, the put option expires worthless. Some of the Company’s purchased put options have deferred premiums. For the deferred premium puts, the Company agrees to pay a premium to the counterparty at the time of settlement.
A call option has an established ceiling price. The buyer of the call option pays the seller a premium to enter into the call option. When the settlement price is above the ceiling price, the seller pays the buyer an amount equal to the difference between the settlement price and the strike price multiplied by the hedged contract volume. When the settlement price is below the ceiling price, the call option expires worthless.
The Company combines swaps, purchased put options, purchased call options, sold put options and sold call options in order to achieve various hedging strategies. Some examples of the Company’s hedging strategies are collars which include purchased put options and sold call options, three-way collars which include purchased put options, sold put options and sold call options, and enhanced swaps, which include either sold put options or sold call options with the associated premiums rolled into an enhanced fixed price swap. The Company has historically relied on commodity derivative contracts to mitigate its exposure to lower commodity prices.
The objective of the Company’s use of commodity derivative instruments is to achieve more predictable cash flows in an environment of volatile oil and natural gas prices and to manage its exposure to commodity price risk. While the use of these commodity derivative instruments limits the downside risk of adverse price movements, such use may also limit the Company’s ability to benefit from favorable price movements. The Company may, from time to time, add incremental derivatives to hedge additional production, restructure existing derivative contracts or enter into new transactions to modify the terms of current contracts in order to realize the current value of the Company’s existing positions. The Company does not enter into derivative contracts for speculative purposes.
To reduce the impact of fluctuations in oil and natural gas prices on the Company's revenues, the Company has periodically entered into commodity derivative contracts with respect to certain of its oil and natural gas production through various transactions that limit the downside of future prices received. The Company plans to continue its practice of entering into such transactions to reduce the impact of commodity price volatility on its cash flow from operations. Future transactions may include price swaps whereby the Company will receive a fixed price for its production and pay a variable market price to the contract counterparty. Additionally, the Company may enter into collars, whereby it receives the excess, if any, of the fixed floor over the floating rate or pay the excess, if any, of the floating rate over the fixed ceiling price. These hedging activities are intended to support oil and natural gas prices at targeted levels and to manage the Company's exposure to oil and natural gas price fluctuations.
The use of derivatives involves the risk that the counterparties to such instruments will be unable to meet the financial terms of such contracts. The Company’s derivative contracts are currently with 10 counterparties.1 counterparty, who is a lender under the Credit Agreement and the DIP Credit Facility. The Company has netting arrangements with the counterpartiescounterparty that provide for the offset of payables against receivables from separate derivative arrangements with the counterparties in the event of contract termination. The derivative contracts may be terminated by a non-defaulting party in the event of default by one of the parties to the agreement. There areis 0 credit risksrisk related contingent features or circumstances in which the features could be triggered in derivative instruments that are in a net liability position at the end of the reporting period.
Effect of Chapter 11 Cases
The commencement of the Chapter 11 Cases constituted a termination event with respect to the Company’s derivative instruments, which permits the counterparties to such derivative instruments to terminate their outstanding hedges. Such termination events are not stayed under the Bankruptcy Code. During June 2020, certain of the lenders under the Credit Agreement elected to terminate their International Swaps and Derivatives Association master agreements and outstanding hedges with the Company for aggregate settlement proceeds of $96.1 million. The proceeds from these terminations were applied to the outstanding borrowings under the Credit Facility. After the June 2020 terminations, the remaining active contracts consisted of the items shown in the table immediately below.
The Company’s open commodity derivative contracts by quarter as of SeptemberJune 30, 20192020 are summarized below:
| | | 2019 | | 2020 | | 2021 | | 2022 | | 2023 | | 9/30/2020 | | 12/31/2020 | | 3/31/2021 | | 6/30/2021 |
| NYMEX WTI Crude Swaps: | NYMEX WTI Crude Swaps: | | | | | | | | | | NYMEX WTI Crude Swaps: | | | | | | | |
| Notional volume (Bbl) | Notional volume (Bbl) | 3,950,000 | | | 3,200,001 | | | 3,000,000 | | | 1,020,000 | | | 900,000 | | Notional volume (Bbl) | 1,400,000 | | | 1,350,000 | | | 750,000 | | | 450,000 | |
| Weighted average fixed price ($/Bbl) | Weighted average fixed price ($/Bbl) | $ | 57.86 | | | $ | 59.81 | | | $ | 57.80 | | | $ | 54.84 | | | $ | 54.87 | | Weighted average fixed price ($/Bbl) | $ | 50.10 | | | $ | 50.10 | | | $ | 60.07 | | | $ | 60.07 | |
| NYMEX WTI Crude Purchased Puts: | NYMEX WTI Crude Purchased Puts: | | NYMEX WTI Crude Purchased Puts: | |
| Notional volume (Bbl) | Notional volume (Bbl) | 200,000 | | | 9,725,001 | | | 1,800,000 | | | — | | | — | | Notional volume (Bbl) | — | | | — | | | 150,000 | | | 150,000 | |
| Weighted average purchased put price ($/Bbl) | Weighted average purchased put price ($/Bbl) | $ | 60.00 | | | $ | 54.99 | | | $ | 55.02 | | | $ | — | | | $ | — | | Weighted average purchased put price ($/Bbl) | $ | — | | | $ | — | | | $ | 55.04 | | | $ | 55.04 | |
| | NYMEX WTI Crude Sold Calls: | NYMEX WTI Crude Sold Calls: | | NYMEX WTI Crude Sold Calls: | |
| Notional volume (Bbl) | Notional volume (Bbl) | 200,000 | | | 9,725,001 | | | 1,800,000 | | | — | | | — | | Notional volume (Bbl) | — | | | — | | | 150,000 | | | 150,000 | |
| Weighted average sold call price ($/Bbl) | Weighted average sold call price ($/Bbl) | $ | 64.00 | | | $ | 62.04 | | | $ | 63.70 | | | $ | — | | | $ | — | | Weighted average sold call price ($/Bbl) | $ | — | | | $ | — | | | $ | 65.00 | | | $ | 65.00 | |
| NYMEX WTI Crude Sold Puts: | NYMEX WTI Crude Sold Puts: | | NYMEX WTI Crude Sold Puts: | |
| Notional volume (Bbl) | Notional volume (Bbl) | 1,000,000 | | | 12,250,002 | | | 4,200,000 | | | 600,000 | | | 600,000 | | Notional volume (Bbl) | — | | | — | | | 900,000 | | | 600,000 | |
| Weighted average sold put price ($/Bbl) | Weighted average sold put price ($/Bbl) | $ | 44.60 | | | $ | 42.91 | | | $ | 43.50 | | | $ | 43.00 | | | $ | 43.00 | | Weighted average sold put price ($/Bbl) | $ | — | | | $ | — | | | $ | 43.92 | | | $ | 43.88 | |
| NYMEX HH Natural Gas Swaps: | NYMEX HH Natural Gas Swaps: | | NYMEX HH Natural Gas Swaps: | |
| Notional volume (MMBtu) | Notional volume (MMBtu) | 9,000,000 | | | 35,400,000 | | | — | | | — | | | — | | Notional volume (MMBtu) | 2,400,000 | | | 2,400,000 | | | — | | | — | |
| Weighted average fixed price ($/MMBtu) | Weighted average fixed price ($/MMBtu) | $ | 2.75 | | | $ | 2.75 | | | $ | — | | | $ | — | | | $ | — | | Weighted average fixed price ($/MMBtu) | $ | 2.76 | | | $ | 2.76 | | | $ | — | | | $ | — | |
| NYMEX HH Natural Gas Purchased Puts: | NYMEX HH Natural Gas Purchased Puts: | | NYMEX HH Natural Gas Purchased Puts: | |
| Notional volume (MMBtu) | Notional volume (MMBtu) | — | | | 600,000 | | | — | | | — | | | — | | Notional volume (MMBtu) | 1,200,000 | | | 1,200,000 | | | — | | | — | |
| Weighted average purchased put price ($/MMBtu) | $ | — | | | $ | 2.90 | | | $ | — | | | $ | — | | | $ | — | | |
| NYMEX HH Natural Gas Sold Calls: | | |
| Notional volume (MMBtu) | — | | | 600,000 | | | — | | | — | | | — | | |
| Weighted average sold call price ($/MMBtu) | $ | — | | | $ | 3.48 | | | $ | — | | | $ | — | | | $ | — | | |
| | CIG Basis Gas Swaps: | | |
| Notional volume (MMBtu) | 11,100,000 | | | 43,200,000 | | | — | | | — | | | — | | |
| Weighted average fixed basis price ($/MMBtu) | Weighted average fixed basis price ($/MMBtu) | $ | (0.72) | | | $ | (0.61) | | | $ | — | | | $ | — | | | $ | — | | Weighted average fixed basis price ($/MMBtu) | $ | (0.60) | | | $ | (0.60) | | | $ | — | | | $ | — | |
The following tables detail the fair value of the Company’s derivative instruments, including the gross amounts and adjustments made to net the derivative instruments for the presentation in the condensed consolidated balance sheets (in thousands):
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | As of September 30, 2019 | | | | | | | | |
| Location on Balance Sheet | | Gross Amounts of Recognized Assets and Liabilities | | Gross Amounts Offsets in the Balance Sheet(1) | | Net Amounts of Assets and Liabilities Presented in the Balance Sheet | | Gross Amounts not Offset in the Balance Sheet(2) | | Net Amounts(3) |
Current assets (4) | | $ | 114,221 | | | $ | (47,741) | | | $ | 66,480 | | | $ | (83) | | | $ | 107,917 | |
| Non-current assets | | $ | 77,188 | | | $ | (35,668) | | | $ | 41,520 | | | $ | — | | | $ | — | |
Current liabilities (4) | | $ | (47,849) | | | $ | 47,741 | | | $ | (108) | | | $ | 83 | | | $ | (108) | |
| Non-current liabilities | | $ | (35,751) | | | $ | 35,668 | | | $ | (83) | | | $ | — | | | $ | — | |
| | | As of December 31, 2018 | | | As of June 30, 2020 | |
| Location on Balance Sheet | Location on Balance Sheet | | Gross Amounts of Recognized Assets and Liabilities | | Gross Amounts Offsets in the Balance Sheet(1) | | Net Amounts of Assets and Liabilities Presented in the Balance Sheet | | Gross Amounts not Offset in the Balance Sheet(2) | | Net Amounts(3) | Location on Balance Sheet | | Gross Amounts of Recognized Assets and Liabilities | | Gross Amounts Offsets in the Balance Sheet(1) | | Net Amounts of Assets and Liabilities Presented in the Balance Sheet | | Gross Amounts not Offset in the Balance Sheet(2) | | Net Amounts(3) |
Current assets (5) | | $ | 115,852 | | | $ | (66,945) | | | $ | 48,907 | | | $ | (192) | | | $ | 57,147 | | |
| Current assets | | Current assets | | $ | 61,226 | | | $ | (5,559) | | | $ | 55,667 | | | $ | — | | | $ | 55,667 | |
| Non-current assets | Non-current assets | | $ | 17,217 | | | $ | (8,785) | | | $ | 8,432 | | | $ | — | | | $ | — | | Non-current assets | | — | | | — | | | — | | | — | | | — | |
Current liabilities (5) | | $ | (67,141) | | | $ | 66,945 | | | $ | (196) | | | $ | 192 | | | $ | (4) | | |
| Current liabilities | | Current liabilities | | (5,559) | | | 5,559 | | | — | | | — | | | — | |
| Non-current liabilities | Non-current liabilities | | $ | (8,785) | | | $ | 8,785 | | | $ | — | | | $ | — | | | $ | — | | Non-current liabilities | | — | | | — | | | — | | | — | | | — | |
| | | | As of December 31, 2019 | |
| Location on Balance Sheet | | Location on Balance Sheet | | Gross Amounts of Recognized Assets and Liabilities | | Gross Amounts Offsets in the Balance Sheet(1) | | Net Amounts of Assets and Liabilities Presented in the Balance Sheet | | Gross Amounts not Offset in the Balance Sheet(2) | | Net Amounts(3) |
| Current assets | | Current assets | | $ | 48,605 | | | $ | (31,051) | | | $ | 17,554 | | | $ | — | | | $ | 30,783 | |
| Non-current assets | | Non-current assets | | 38,034 | | | (24,805) | | | 13,229 | | | — | | | — | |
| Current liabilities | | Current liabilities | | (33,049) | | | 31,051 | | | (1,998) | | | — | | | (2,106) | |
| Non-current liabilities | | Non-current liabilities | | (24,913) | | | 24,805 | | | (108) | | | — | | | — | |
(1)Agreements are in place with all of the Company’s financial trading counterparties that allow for the financial right of offset for derivative assets and derivative liabilities at settlement or in the event of a default under the agreements.
(2)Netting for balance sheet presentation is performed by current and non-current classification. This adjustment represents amounts subject to an enforceable master netting arrangement, which are not netted on the condensed consolidated balance sheets. There are no amounts of related financial collateral received or pledged.
(3)Net amounts are not split by current and non-current. All counterparties in a net asset position are shown in the current asset line, item and all counterparties in a net liability position are shown in the current liability line item.
(4)Gross current liabilities include a deferred premium liability of $1.7 million related to the Company's deferred premiums. Gross current assets include a deferred premium asset of $0.4 million related to the Company's deferred premiums.
(5)Gross current liabilities include a deferred premium liability of $7.7 million related to the Company's deferred put premiums. Gross current assets include a deferred premium asset of $0.8 million related to the Company's deferred put premiums.
The table below sets forth the commodity derivatives gain (loss) for the three and ninesix months ended SeptemberJune 30, 20192020 and 20182019 (in thousands). Commodity derivatives gain (loss) isare included under the other income (expense) line item in the condensed consolidated statements of operations.
| | | | | | | | | | | | | | | | | | | | | | | |
| For the Three Months Ended September 30, | | | | For the Nine Months Ended September 30, | | |
| 2019 | | 2018 | | 2019 | | 2018 |
| Commodity derivatives gain (loss) | $ | 87,956 | | | $ | (35,913) | | | $ | 39,383 | | | $ | (175,752) | |
| | | | | | | | | | | | | | | | | | | | | | | |
| For the Three Months Ended June 30, | | | | For the Six Months Ended June 30, | | |
| 2020 | | 2019 | | 2020 | | 2019 |
| Commodity derivatives gain (loss) | $ | (69,301) | | | $ | 73,519 | | | $ | 193,714 | | | $ | (48,572) | |
Note 6—8—Asset Retirement Obligations
The Company follows accounting for asset retirement obligations in accordance with ASC 410— Asset Retirement and Environmental Obligations, which requires that the fair value of a liability for an asset retirement obligation be recognized in the period in which it was incurred if a reasonable estimate of fair value could be made. The Company’s asset retirement obligations primarily represent the estimated present value of the amounts expected to be incurred to plug, abandon and remediate producing and shut-in wells at the end of their productive lives in accordance with applicable local, state and federal laws, and applicable lease terms. The Company determines the estimated fair value of its asset retirement obligations by calculating the present value of estimated cash flows related to plugging and abandonment liabilities. The significant inputs used to calculate such liabilities include estimates of costs to be incurred, the Company’s credit adjusted discount rates,
inflation rates and estimated dates of abandonment. The asset retirement liability is accreted to its present value each period and the capitalized asset retirement costs are depleted with proved oil and gas properties using the unit of production method. Asset retirement obligations are currently presented in liabilities subject to compromise on the condensed consolidated balance sheets.
The following table summarizes the activities of the Company’s asset retirement obligations for the period indicated (in thousands):
| | | | | | | |
| For the NineSix Months Ended SeptemberJune 30, 20192020 | | |
| Balance beginning of period | $ | 69,79195,908 | | | |
| Liabilities incurred or acquired | 315197 | | | |
| Liabilities settled | (15,484)(16,398) | | | |
| Revisions in estimated cash flows | 35,4667,011 | | | |
| Accretion expense | 3,8383,475 | | | |
| Balance end of period | $ | 93,92690,193 | | | |
Note 7—9—Fair Value Measurements
ASC 820, Fair Value Measurement and Disclosure, establishes a hierarchy for inputs used in measuring fair value that maximizes the use of observable inputs and minimizes the use of unobservable inputs by requiring that the most observable inputs be used when available. Observable inputs are inputs that market participants would use in pricing the asset or liability developed based on market data obtained from sources independent of the Company. Unobservable inputs are inputs that reflect the Company’s assumptions of what market participants would use in pricing the asset or liability developed based on the best information available in the circumstances. The hierarchy is broken down into three levels based on the reliability of the inputs as follows:
•Level 1: Quoted prices are available in active markets for identical assets or liabilities;
•Level 2: Quoted prices in active markets for similar assets and liabilities that are observable for the asset or liability;
•Level 3: Unobservable pricing inputs that are generally less observable from objective sources, such as discounted cash flow models or valuations.
The financial assets and liabilities are classified based on the lowest level of input that is significant to the fair value measurement. The Company’s assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of the fair value of assets and liabilities and their placement within the fair value hierarchy levels. There were no transfers between levels during any periods presented below.
The following table presents the Company’s financial assets and liabilities that were accounted for at fair value on a recurring basis as of SeptemberJune 30, 20192020 and December 31, 20182019 by level within the fair value hierarchy (in thousands):
| | | Fair Value Measurement at September 30, 2019 | | | Fair Value Measurement at June 30, 2020 | |
| | Level 1 | | Level 2 | | Level 3 | | Total | | Level 1 | | Level 2 | | Level 3 | | Total |
| Financial Assets: | Financial Assets: | | | | | | | | Financial Assets: | | | | | | | |
| Commodity derivative assets | Commodity derivative assets | $ | — | | | $ | 108,000 | | | $ | — | | | $ | 108,000 | | Commodity derivative assets | $ | — | | | $ | 55,667 | | | $ | — | | | $ | 55,667 | |
| Financial Liabilities: | Financial Liabilities: | | Financial Liabilities: | |
| Commodity derivative liabilities | Commodity derivative liabilities | $ | — | | | $ | 191 | | | $ | — | | | $ | 191 | | Commodity derivative liabilities | $ | — | | | $ | — | | | $ | — | | | $ | — | |
| | | Fair Value Measurement at December 31, 2018 | | | Fair Value Measurement at December 31, 2019 | |
| | Level 1 | | Level 2 | | Level 3 | | Total | | Level 1 | | Level 2 | | Level 3 | | Total |
| Financial Assets: | Financial Assets: | | | | | | | | Financial Assets: | | | | | | | |
| Commodity derivative assets | Commodity derivative assets | $ | — | | | $ | 57,339 | | | $ | — | | | $ | 57,339 | | Commodity derivative assets | $ | — | | | $ | 30,783 | | | $ | — | | | $ | 30,783 | |
| Financial Liabilities: | Financial Liabilities: | | Financial Liabilities: | |
| Commodity derivative liabilities | Commodity derivative liabilities | $ | — | | | $ | 196 | | | $ | — | | | $ | 196 | | Commodity derivative liabilities | $ | — | | | $ | 2,106 | | | $ | — | | | $ | 2,106 | |
The following methods and assumptions were used to estimate the fair value of the assets and liabilities in the tabletables above:
Commodity Derivative Instruments
The Company determines its estimate of the fair value of derivative instruments using a market-basedmarket based approach that takes into account several factors, including quoted market prices in active markets, implied market volatility factors, quotes from third parties, the credit rating of each counterparty, and the Company’sCompany's own credit rating. In consideration of counterparty credit risk, the Company assessed the possibility of whether each counterparty to the derivative would default by failing to make any contractually required payments. Additionally, the Company considers that it is of substantial credit quality and has the financial resources and willingness to meet its potential repayment obligations associated with the derivative transactions. Derivative instruments utilized by the Company consist of swaps, put options and, call options. The oil and natural gas derivative markets are highly active. Although the Company’s derivative instruments are valued using public indices, the instruments themselves are traded with third party counterparties and are not openly traded on an exchange. As such, the Company has classified these instruments as Level 2.
Fair Value of Financial Instruments
The Company’sCompany's financial instruments consist primarily of cash and cash equivalents, accounts receivable, accounts payable, commodity derivative instruments (discussed above) and long-term debt. As of June 30, 2020, the Senior Notes were reclassified to liabilities subject to compromise. The carrying values of cash and cash equivalents, accounts receivable and accounts payable are representative of their fair values due to their short-term maturities. The carrying amountamounts of the Company’s credit facilityCredit Facility and DIP Credit Facility approximated fair value as it bears interest at variable rates over the term of the loan. The fair values of the 2024 Senior Notes and 2026 Senior Notes were derived from available market data. As such, the Company has classified the 2024 Senior Notes and 2026 Senior Notes as Level 2. Please refer to Note 4 - 6—Long-Term Debt for further information. The Company’s policy is to recognize transfers between levels at the end of the period. This disclosure (in thousands) does not impact the Company’sCompany's financial position, results of operations or cash flows.
| | | At September 30, 2019 | | | At December 31, 2018 | | | At June 30, 2020 | | | At December 31, 2019 | |
| | Carrying Amount | | Fair Value | | Carrying Amount | | Fair Value | | Carrying Amount | | Fair Value | | Carrying Amount | | Fair Value |
| Credit Facility | Credit Facility | $ | 550,000 | | | $ | 550,000 | | | $ | 285,000 | | | $ | 285,000 | | Credit Facility | $ | 481,935 | | | $ | 481,935 | | | $ | 470,000 | | | $ | 470,000 | |
| DIP Credit Facility | | DIP Credit Facility | $ | 37,500 | | | $ | 37,500 | | | $ | — | | | $ | — | |
2024 Senior Notes(1) | 2024 Senior Notes(1) | $ | 394,577 | | | $ | 262,000 | | | $ | 393,866 | | | $ | 330,000 | | 2024 Senior Notes(1) | $ | 400,000 | | | $ | 77,404 | | | $ | 394,824 | | | $ | 250,000 | |
2026 Senior Notes(2) | 2026 Senior Notes(2) | $ | 690,640 | | | $ | 428,865 | | | $ | 738,793 | | | $ | 558,750 | | 2026 Senior Notes(2) | $ | 700,189 | | | $ | 140,038 | | | $ | 690,953 | | | $ | 420,113 | |
(1)The carrying amount of the 2024 Senior Notes includes 0 unamortized debt issuance costs as of $5.4 millionJune 30, 2020 and $6.1$5.2 million as of September 30, 2019 and December 31, 2018, respectively.2019.
(2)The carrying amount of the 2026 Senior Notes includes 0 unamortized debt issuance costs as of $9.5 millionJune 30, 2020 and $11.2$9.2 million as of September 30, 2019 and December 31, 2018, respectively.2019.
Non-Recurring Fair Value Measurements
The Company applies the provisions of the fair value measurement standard on a non-recurring basis to its non-financial assets and liabilities, including proved property. These assets and liabilities are not measured at fair value on a recurring basis, but are subject to fair value adjustments when facts and circumstances arise that indicate a need for remeasurement.
The Company utilizes fair value on a non-recurring basis to review its proved oil and gas properties for potential impairment when events and circumstances indicate, and at least annually, a possible decline in the recoverability of the carrying value of such property. The Company uses an income approach analysis based on the net discounted future cash flows of producing property. The future cash flows are based on management’s estimates for the future. Unobservable inputs include estimates of oil and gas production, as the case may be, from the Company’s reserve
reports, commodity prices based on the sales contract terms and forward price curves, operating and development costs and a discount rate based on a market-based weighted average cost of capital (all of which are Level 3 inputs within the fair value hierarchy). For the three and six months ended SeptemberJune 30, 2019,2020, the Company recognized 0 impairment expense on its proved oil$0.8 million and gas properties. For the nine months ended September 30, 2019, the Company recognized $11.2$1.6 million, of impairment expense on its proved oil and gas properties.
The fair value did not exceed the Company's carrying amount associated with its proved oil and gas properties in its northern field. For the three and nine months ended September 30, 2018, the Company recognized $16.2 millionrespectively, in impairment expense on its proved oil and gas properties related to impairment of assets in its northern field. The fair value did not exceedFor the Company's carrying amount associated withthree and six months ended June 30, 2019, the Company recognized $3.0 million and $11.2 million, respectively, in impairment expense on its proved oil and gas properties related to impairment of assets in its northern field.
The Company’s other non-recurring fair value measurements include the purchase price allocations for the fair value of assets and liabilities acquired through business combinations. The fair value of assets and liabilities acquired through business combinations is calculated using a discounted cash flow approach using Level 3 inputs. Cash flow estimates require forecasts and assumptions for many years into the future for a variety of factors, including risk-adjusted oil and gas reserves, commodity prices, development costs and operating costs, based on market participant assumptions. The fair value of assets or liabilities associated with purchase price allocations is on a non-recurring basis and is not measured in periods after initial recognition.
Note 8—10—Income Taxes
The Company computes an estimated annual effective tax rate (“AETR”) each quarter based on the current and forecasted operating results. The income tax expense or benefit associated with the interim period is computed using the most recent estimated annual effective rateAETR applied to the year-to-date ordinary income or loss, plus the tax effect of any significant discrete or infrequently occurring items recorded during the interim period. The computation of the annual estimated effective tax rateAETR at each interim period requires certain estimates and significant judgmentjudgements including, but not limited to, the expected operating income (loss) for the year, projections of the proportion of income earned and taxed in various jurisdictions, permanent differences and the likelihood of recovering deferred tax assets generated in the current year. The accounting estimates used to compute the provision for income taxes may change as new events occur, more experience is obtained, and additional information becomes known or as the tax environment changes.
The effective combined U.S. federal and state income tax rate for the ninesix months ended SeptemberJune 30, 2020 and 2019 was negative 5.7%. During the nine months ended September 30, 2019, the Company recognized income tax expense of $0.9 million.(0.8)% and 21.6%, respectively. The effective rate for the ninesix months ended SeptemberJune 30, 2020 and 2019 differs from the amount that would be provided by applying the statutory U.S. federal income tax rate of 21.0% primarily21% to pre-tax income due to (i) the effect of a full valuation allowance in effect at June 30, 2020 and (ii) the effects of state income taxes, and estimated permanent differences. The significanttaxable differences, during the nine months ended September 30, 2019 as compared with nine months ended months ended September 30, 2018 includedand income attributable to non-controlling interest andfor the six months ended June 30, 2019. Before accounting for a discrete item regardingnaked credit deferred tax liability, net tax expense for the three months ended June 30, 2020 was reduced to zero due to the valuation allowance. The naked credit deferred tax deficiencyliability results in tax expense of $2.2 million for the six months ended June 30, 2020.
The Company considers whether some portion, or all, of the stock-based compensation compareddeferred tax assets (“DTAs”) will be realized based on a more likely than not standard of judgment. The ultimate realization of DTAs is dependent upon the generation of future taxable income during the periods in which those temporary differences become deductible. At December 31, 2019, the Company had a valuation allowance totaling $246.1 million against its DTAs resulting from prior year cumulative financial losses, oil and gas impairments, and significant net operating losses for U.S. federal and state income tax. The Company assesses the appropriateness of its valuation allowance on a quarterly basis. As of June 30, 2020, there was no change in the Company’s assessment of the realizability of its DTAs, except for a naked credit deferred tax liability.
On July 13, 2020 the Bankruptcy Court entered a final order approving certain procedures (including notice requirements) that certain shareholders and potential shareholders must comply with regarding transfers of, or declarations of worthlessness with respect to, the compensation recognized for financial reporting purposes. The cumulative effectCompany’s common stock and preferred stock, as well as certain obligations with respect to notifying the Company with respect to current share ownership, each of which are intended to preserve the Company’s ability to use its net operating losses to offset possible future U.S. taxable income by reducing the likelihood of an ownership change under Section 382 of the estimated permanent differences and discrete items applied toCode during the pre-tax book loss forpendency of the nine months ended September 30, 2019 resulted in an income tax expense and associated negative income tax rate. The Company anticipates the potential for increased periodic volatility in future effective tax rates from the impact of stock-based compensation tax deductions as they are treated as discrete tax items.Chapter 11 Cases.
Note 9—11—Stock-Based Compensation
Extraction Long Term Incentive Plan
In October 2016, the Company’s board of directors adopted the Extraction Oil & Gas, Inc. 2016 Long Term Incentive Plan (the “2016 Plan” or “LTIP”), pursuant to which employees, consultants and directors of the Company and its affiliates performing services for the Company are eligible to receive awards. The 2016 Plan provides for the grant of stock options, stock appreciation rights, restricted stock, restricted stock units, bonus stock, dividend equivalents, other stock-based awards, substitute awards, annual incentive awards and performance awards intended to align the interests of participants with those of stockholders. In May 2019, the Company's stockholders approved the amendment and
restatement of the Company's 2016 Long Term Incentive Plan. The amended and restated 2016 Long Term Incentive Plan provides a total reserve of 32.2 million shares of common stock for issuance pursuant to awards under the LTIP. Extraction has granted awards under the LTIP to certain directors, officers and employees, including stock options, restricted stock units, performance stock awards, performance stock units, performance cash awards and cash awards.
Restricted Stock Units
Restricted stock units granted under the LTIP (“RSUs”) generally vest over either a one or three-year service period, with 100% vesting in year one or 25%, 25% and 50% of the units vesting in year one, two and three, respectively. Grant date fair value was determined based on the value of Extraction’s common stock pursuant to the terms of the LTIP. The Company assumed a forfeiture rate of 0 as part of the grant date estimate of compensation cost.
The Company recorded $6.6$1.7 million and $20.6$2.5 million of stock-based compensation costs related to RSUs for the three and ninesix months ended SeptemberJune 30, 2019,2020, respectively, as compared to $7.1 million and $20.7$14.0 million for the three and ninesix months ended SeptemberJune 30, 2018,2019, respectively. These costs were included in the condensed consolidated statements of operations within the general and administrative expenses line item. As of SeptemberJune 30, 2019,2020, there was $16.5$5.5 million of total unrecognized compensation cost related to the unvested RSUs granted to certain directors, officers and employees that is expected to be recognized over a weighted average period of 1.5 years.
The following table summarizes the RSU activity from January 1, 20192020 through SeptemberJune 30, 20192020 and provides information for RSUs outstanding at the dates indicated.
| | | Number of Shares | | Weighted Average Grant Date
Fair Value | | Number of Shares | | Weighted Average Grant Date
Fair Value |
| Non-vested RSUs at January 1, 2019 | 3,102,335 | | | $ | 16.91 | | |
| Non-vested RSUs at January 1, 2020 | | Non-vested RSUs at January 1, 2020 | 2,635,765 | | | $ | 8.32 | |
| Granted | Granted | 1,901,418 | | | $ | 4.76 | | Granted | 1,409,765 | | | $ | 0.75 | |
| Forfeited | Forfeited | (280,029) | | | $ | 12.91 | | Forfeited | (1,790,568) | | | $ | 2.84 | |
| Vested | Vested | (1,011,340) | | | $ | 15.33 | | Vested | (966,918) | | | $ | 9.17 | |
| Non-vested RSUs at September 30, 2019 | 3,712,384 | | | $ | 11.42 | | |
| Non-vested RSUs at June 30, 2020 | | Non-vested RSUs at June 30, 2020 | 1,288,044 | | | $ | 7.02 | |
Performance Stock Awards
The Company granted performance stock awards ("PSAs") to certain executives under the LTIP in October 2017, March 2018, April 2019 and April 2019.March 2020. The number of shares of the Company's common stock that may be issued to settle these various PSAs ranges from zero to two times the number of PSAs awarded. PSA's that settle in cash are presented as liability based awards. Generally, the shares issued for PSAs are determined based on the satisfaction of a time-based vesting schedule and a weighting of one or more of the following: (i) absolute total stockholder return ("ATSR"), (ii) relative total stockholder return ("RTSR"), as compared to the Company's peer group and (iii) cash return on capital invested ("CROCI") or return on invested capital ("ROIC") measured over a three-year period and vest in their entirety at the end of the three-year measurement period. Any PSAs that have not vested at the end of the applicable measurement period are forfeited. The vesting criterion that is associated with the RTSR is based on a comparison of the Company's total shareholder return for the measurement period compared to that of a group of peer companies for the same measurement period. As the ATSR and RTSR vesting criteria are linked to the Company's share price, they each are considered a market condition for purposes of calculating the grant-date fair value of the awards. The vesting criterion that is associated with the CROCI and ROIC are considered a performance condition for purposes of calculating the grant-date fair value of the awards.
The fair value of the PSAs was measured at the grant date with a stochastic process method using a Monte Carlo simulation. A stochastic process is a mathematically defined equation that can create a series of outcomes over time. Those outcomes are not deterministic in nature, which means that by iterating the equations multiple times, different results will be obtained for those iterations. In the case of the Company's PSAs, the Company cannot predict with certainty the path its stock price or the stock prices of its peer will take over the performance period. By using a stochastic simulation, the Company can create multiple prospective stock pathways, statistically analyze these simulations, and ultimately make inferences regarding the most likely path the stock price will take. As such, because
future stock prices are stochastic, or probabilistic with some direction in nature, the stochastic method, specifically the Monte Carlo Model, is deemed an appropriate method by which to determine the fair value of the PSAs. Significant assumptions used in this simulation include the Company's expected volatility, risk-free interest rate based on U.S. Treasury yield curve rates with maturities consistent with the measurement period as well as the volatilities for each of the Company's peers.
The Company recorded $0.7$0.8 million and $6.8$0.1 million of stock-based compensation costs related to PSAs for the three and ninesix months ended SeptemberJune 30, 2019,2020, respectively, as compared to $1.6$4.6 million and $4.2$6.1 million of stock-based compensation costs related to PSAs for the three and ninesix months ended SeptemberJune 30, 2018,2019, respectively. These costs were included in the condensed consolidated statements of operations within the general and administrative expenses line item. As of SeptemberJune 30, 2019,2020, there was $9.3$2.6 million of total unrecognized compensation cost related to the unvested PSAs granted to certain executives that is expected to be recognized over a weighted average period of 1.20.8 years.
The following table summarizes the PSA activity from January 1, 20192020 through SeptemberJune 30, 20192020 and provides information for PSAs outstanding at the dates indicated.
| | | Number of Shares (1) | | Weighted Average Grant Date
Fair Value | | Number of Shares (1) | | Weighted Average Grant Date
Fair Value |
| Non-vested PSAs at January 1, 2019 | 2,794,083 | | | $ | 9.00 | | |
| Non-vested PSAs at January 1, 2020 | | Non-vested PSAs at January 1, 2020 | 2,863,190 | | | $ | 7.72 | |
| Granted | Granted | 1,646,218 | | | $ | 5.44 | | Granted | 5,952,700 | | | $ | 0.29 | |
Forfeited | Forfeited | — | | | $ | — | | Forfeited | (5,881,200) | | | $ | (0.29) | |
| Vested | Vested | — | | | $ | — | | Vested | — | | | $ | — | |
| Non-vested PSAs at September 30, 2019 | 4,440,301 | | | $ | 7.68 | | |
| Non-vested PSAs at June 30, 2020 | | Non-vested PSAs at June 30, 2020 | 2,934,690 | | | $ | 7.53 | |
(1)The number of awards assumes that the associated maximum vesting condition is met at the target amount. The final number of shares of the Company's common stock issued may vary depending on the performance multiplier, which ranges from zero to one for the 2017 and 2018 grants and ranges from zero to two for the 2019 and 2020 grants, depending on the level of satisfaction of the vesting condition.
(2)The Company approved retention agreements on June 12, 2020 with certain executives and senior managers. These retention agreements, are subject to repayment upon a resignation without “good reason” or termination of employment for “cause” before specified dates and events. As a condition to participating in the revised compensation program, the equity compensation awards granted in 2020 were cancelled.
Stock Options
Expense on the stock options is recognized on a straight-line basis over the service period of the award less awards forfeited. The fair value of the stock options was measured at the grant date using the Black-Scholes valuation model. The Company utilizes the "simplified" method to estimate the expected term of the stock options granted as there is limited historical exercise data available in estimating the expected term of the stock options. Expected volatility is based on the volatility of the historical stock prices of the Company’s peer group. The risk-free rates are based on the yields of U.S. Treasury instruments with comparable terms. A dividend yield and forfeiture rate of zero were assumed. Stock options granted under the LTIP vest ratably over three years and are exercisable immediately upon vesting through the tenth anniversary of the grant date. To fulfill options exercised, the Company will issue new shares.
The Company recorded $4.0 million and $11.5 million of0 stock-based compensation costs related to the stock options for the three and ninesix months ended SeptemberJune 30, 2019, respectively,2020, as compared to $3.8$3.7 million and $11.3$7.5 million for the three and ninesix months ended SeptemberJune 30, 2018,2019, respectively. These costs were included in the condensed consolidated statements of operations within the general and administrative expenses line item. As of SeptemberJune 30, 2019,2020, there was $0.7 million ofare 0 remaining unrecognized compensation costcosts related to the stock options that is expectedgranted to be recognized over a weighted average period of 0.1 years.certain executives.
The following table summarizes the
There was no stock option activity from January 1, 20192020 through SeptemberJune 30, 20192020. However, as of June 30, 2020, there was approximately 5.2 million outstanding and provides information forexercisable stock options outstanding at the dates indicated.
| | | | | | | | | | | |
| Number of Options | | Weighted Average Exercise Price |
| Non-vested Stock Options at January 1, 2019 | 1,748,148 | | | $ | 18.50 | |
| Granted | — | | | $ | — | |
| Forfeited | — | | | $ | — | |
| Vested | (543,977) | | | $ | 18.72 | |
| Non-vested Stock Options at September 30, 2019 | 1,204,171 | | | $ | 18.41 | |
Incentive Restricted Stock Units
Officers of the Company contributed 2.7 million shares of common stock to Extraction Employee Incentive, LLC (“Employee Incentive”), which is owned solely by certain officers of the Company. Employee Incentive issued restricted stock units (“Incentive RSUs”) to certain employees. Incentive RSUs vested over a three year service period, with 25%, 25% and 50% of the units vesting in year one, two and three, respectively. On July 17, 2017, the partners of Employee Incentive amended the vesting schedule in which 25% vested immediately and the remaining Incentive RSUs vest 25%, 25% and 25% each six months thereafter, over the remaining 18-month service period. Grant date fair value was determined based on the
value of Extraction’sthe Company's common stock on the date of issuance. The Company assumed a forfeiture rate of 0 as part of the grant date estimate of compensation cost.
The Company recorded 0 stock-based compensation costs related to Incentive RSUs for the three and six months ended SeptemberJune 30, 2020. The Company recorded 0 stock-based compensation costs related to Incentive RSUs for the three months ended June 30, 2019. The Company recorded $0.8 million of stock-based compensation costs related to Incentive RSUs for the ninesix months ended SeptemberJune 30, 2019. The Company recorded $4.9 million and $14.7 million of stock-based compensation costs related to Incentive RSUs for the three and nine months ended September 30, 2018, respectively. These costs were included in the condensed consolidated statements of operations within the general and administrative expenses line item. As of SeptemberJune 30, 2019,2020, there are no remaining unrecognized compensation costs related to the Incentive RSUs granted to certain employees.
Note 12—Equity
Series A Preferred Stock
The holders of our Series A Preferred Stock (the "Series A Preferred Holders") are entitled to receive a cash dividend of 5.875% per year, payable quarterly in arrears, and the Company has the ability to pay such quarterly dividends in kind at a dividend rate of 10% per year (decreased proportionately to the extent such quarterly dividends are partially paid in cash). The Company has paid the quarterly dividends in kind from the fourth quarter of 2019 until the filing of the Chapter 11 Cases. Because certain provisions within the RSA and the DIP Credit Agreement restrict the Company's ability to declare a dividend, the Company has not made any dividend payments on the Series A Preferred Stock since the commencement of the Chapter 11 Cases. The Series A Preferred Stock is convertible into shares of our common stock at the election of the Series A Preferred Holders at a conversion ratio per share of Series A Preferred Stock of 61.9195. Until the three-year anniversary of the closing of the IPO, the Company could elect to convert the Series A Preferred Stock at a conversion ratio per share of Series A Preferred Stock of 61.9195, but only if the closing price of our common stock had traded at or above a certain premium to our initial offering price, such premium to decrease with time. On October 15, 2019, the three year anniversary had passed for the Series A Preferred Stock to convert into our common stock. Prior to the commencement of the Chapter 11 Cases, the Company could have redeemed the Series A Preferred Stock for the liquidation preference, which was $198.7 million on June 14, 2020. In certain situations, including a change of control, the Series A Preferred Stock may be redeemed for cash in an amount equal to the greater of (i) 135% of the liquidation preference of the Series A Preferred Stock and (ii) a 17.5% annualized internal rate of return on the liquidation preference of the Series A Preferred Stock. The Series A Preferred Stock matures on October 15, 2021, at which time they are mandatorily redeemable for cash at the liquidation preference to the extent there are legally available funds to do so. For more information, see the Company’s Annual Report.
Elevation Common Units
On May 1, 2020, Elevation's board of managers issued 1,530,000,000 common units at a price of $0.01 per unit to certain of Elevation's members other than Extraction through the Capital Raise. The Capital Raise caused Extraction's ownership of Elevation to be diluted to less than 0.01%. As a result of the Capital Raise, beginning in May 2020 Extraction began accounting for Elevation under the cost method of accounting. The Company reserves all rights related to actions taken by Elevation’s board of managers.
Elevation Preferred Units
In July 2018 and July 2019, respectively, Elevation sold 150,000 and 100,000 of Elevation Preferred Units at a price of $990 per unit to a third party (the "Purchaser"). The aggregate liquidation preference when the units were sold was $150.0 million and $100.0 million, respectively. These Preferred Units represent the noncontrolling interest presented on the condensed consolidated balance sheets, condensed consolidated statements of operations and condensed consolidated statements of changes in stockholders' equity and noncontrolling interest for periods ended on or prior to December 31, 2019. As part of the July 2018 transaction, the Company committed to Elevation that it would drill at least 425 qualifying wells in the acreage dedicated to Elevation by December 31, 2023, subject to reductions if Elevation does not invest the full amount of capital as initially anticipated. Pursuant to the Fourth Amendment to the Elevation Gathering Agreements between Elevation and Extraction, this drilling commitment would be eliminated, if and only if all Elevation Preferred Units have been redeemed in full or are otherwise no longer outstanding. Please see Note 14—Commitments and Contingencies — Elevation Gathering Agreements for further details.
Upon deconsolidation of Elevation Midstream, LLC as discussed in Note 1—Business and Organization -Deconsolidation of Elevation Midstream, LLC, the $270.5 million Elevation preferred unit balance in the noncontrolling interest line item of the condensed consolidated balance sheets as of March 31, 2020 was removed. The amount comprises the line item effects of deconsolidation of Elevation Midstream, LLC on the condensed consolidated statements of changes in stockholders' equity and noncontrolling interest as of March 31, 2020.
During the twenty-eight months following table summarizes the Incentive RSU activityJuly 3, 2018 Preferred Unit closing date, Elevation is required to pay the Purchaser a quarterly commitment fee payable in cash or in kind of 1.0% per annum on any undrawn amounts of such additional $250.0 million commitment. For the three months ended June 30, 2020, due to the deconsolidation of Elevation during the first quarter of 2020, the Company's condensed consolidated statements excluded all commitment fees paid-in-kind from January 1, 2019 through Septemberthe Preferred Unit commitment fees and dividends paid-in-kind line item in the condensed consolidated statements of changes in stockholders' equity and noncontrolling interest. For the three months ended June 30, 2019, Elevation recognized $0.9 million of commitment fees paid-in-kind. For the six months ended June 30, 2020 and provides information for Incentive RSUs outstanding2019, respectively, Elevation recognized $0.6 million and $1.8 million of commitment fees paid-in-kind.
The Elevation Preferred Units entitle the Purchaser to receive quarterly dividends at a rate of 8.0% per annum. In respect of quarters ending prior to and including June 30, 2020, the Dividend is payable in cash or in kind at the dates indicated.
| | | | | | | | | | | |
| Number of Shares | | Weighted Average Grant Date
Fair Value |
| Non-vested Incentive RSUs at January 1, 2019 | 476,000 | | | $ | 20.45 | |
| Granted | — | | | $ | — | |
| Forfeited | — | | | $ | — | |
| Vested | (476,000) | | | $ | 20.45 | |
| Non-vested Incentive RSUs at September 30, 2019 | — | | | $ | — | |
Note 10—13—Earnings (Loss) Per Share
Basic earnings per share (“EPS”) includes no dilution and is computed by dividing net income (loss) available to common shareholders by the weighted average number of shares outstanding during the period. Diluted EPS reflects the potential dilution of securities that could share in the earnings of the Company.
The Company uses the “if-converted” method to determine potential dilutive effects of the Company’s outstanding Series A Preferred Stock (the “Series A Preferred Stock”) and the treasury method to determine the potential dilutive effects of outstanding restricted stock awards and stock options. The basic weighted average shares outstanding calculation is based on the actual days in which the shares were outstanding for the three and ninesix months ended SeptemberJune 30, 20192020 and 2018.2019.
The components of basic and diluted EPS were as follows (in thousands, except per share data):
| | For the Three Months Ended | | | For the Nine Months Ended | | |
| | September 30, | | | September 30, | | | | | | | | | | | | | | | | | | | | | | | |
| | 2019 | | 2018 | | 2019 | | 2018 | | For the Three Months Ended June 30, | | | For the Six Months Ended June 30, | |
| | As restated | | | | As restated | | | | 2020 | | 2019 | | 2020 | | 2019 |
| Basic and Diluted Income (Loss) Per Share | Basic and Diluted Income (Loss) Per Share | | Basic and Diluted Income (Loss) Per Share | | | | | | | |
| Net income (loss) | Net income (loss) | $ | 33,924 | | | $ | 65,150 | | | $ | (16,664) | | | $ | 22,003 | | Net income (loss) | $ | (291,934) | | | $ | 43,444 | | | $ | (282,897) | | | $ | (50,588) | |
| Less: Noncontrolling interest | Less: Noncontrolling interest | (5,776) | | | (3,305) | | | (13,849) | | | (3,305) | | Less: Noncontrolling interest | — | | | (4,097) | | | (6,160) | | | (8,072) | |
| Less: Adjustment to reflect Series A Preferred Stock dividends | Less: Adjustment to reflect Series A Preferred Stock dividends | (2,721) | | | (2,721) | | | (8,164) | | | (8,164) | | Less: Adjustment to reflect Series A Preferred Stock dividends | (4,001) | | | (2,722) | | | (8,749) | | | (5,443) | |
| Less: Adjustment to reflect accretion of Series A Preferred Stock discount | Less: Adjustment to reflect accretion of Series A Preferred Stock discount | (1,682) | | | (1,515) | | | (4,915) | | | (4,429) | | Less: Adjustment to reflect accretion of Series A Preferred Stock discount | (1,817) | | | (1,637) | | | (3,587) | | | (3,233) | |
| Adjusted net loss available to common shareholders, basic and diluted | $ | 23,745 | | | $ | 57,609 | | | $ | (43,592) | | | $ | 6,105 | | |
| Adjusted net income (loss) available to common shareholders, basic and diluted | | Adjusted net income (loss) available to common shareholders, basic and diluted | $ | (297,752) | | | $ | 34,988 | | | $ | (301,393) | | | $ | (67,336) | |
| Denominator: | Denominator: | | | | | | | | Denominator: | | | | | | | |
Weighted average common shares outstanding, basic and diluted (1) (2) | Weighted average common shares outstanding, basic and diluted (1) (2) | 137,789 | | | 175,814 | | | 155,847 | | | 175,269 | | Weighted average common shares outstanding, basic and diluted (1) (2) | 138,163 | | | 159,410 | | | 137,945 | | | 165,025 | |
| Income (Loss) Per Common Share | | |
| Loss Per Common Share | | Loss Per Common Share | |
| Basic and diluted | Basic and diluted | $ | 0.17 | | | $ | 0.33 | | | $ | (0.28) | | | $ | 0.03 | | Basic and diluted | $ | (2.16) | | | $ | 0.22 | | | $ | (2.18) | | | $ | (0.41) | |
(1)For the three and ninesix months ended SeptemberJune 30, 2019, 8,956,8122020, 6,532,472 potentially dilutive shares, including restricted stock awards and stock options outstanding, were not included in the calculation above, as they had an anti-dilutive effect on EPS. Additionally, 11,472,445 common shares associated with the assumed conversion of Series A Preferred Stock were also excluded, as they would have had an anti-dilutive effect on EPS.
(2)DilutiveFor the three and six months ended June 30, 2019, 9,547,925 potentially dilutive shares, including restricted stock awards of 347,343 and 537,706 for the three and nine months ended September 30, 2018, respectively,stock options outstanding, were excluded fromnot included in the calculation above, as the impact of these awards were inconsequential to dilutive weighted average shares outstanding and dilutivethey had an anti-dilutive effect on EPS. Additionally, for the three and nine months ended September 30, 2018, 5,244,428 common shares for stock options were excluded as they were out-of-the-money and 11,472,445 common shares associated with the assumed conversion of Series A Preferred Stock were also excluded, as they would have had an anti-dilutive effect on EPS.
Note 11—14—Commitments and Contingencies
Chapter 11 Cases
On June 14, 2020, the Company filed the Chapter 11 Cases seeking relief under the Bankruptcy Code. The Company continues to operate its business and manage its properties in the ordinary course of business pursuant to the applicable provisions of the Bankruptcy Code. In addition, commencement of the Chapter 11 Cases automatically stayed all of the proceedings and actions against the Company (other than regulatory enforcement matters), including those noted below. Please refer to Note 1—Business and Organization for more information on the Chapter 11 Cases.
General
As is customary in the oil and gas industry, the Company may at times have commitments in place to reserve or earn certain acreage positions or wells. If the Company does not meet such commitments, the acreage positions or wells may be lost, or the Company may be required to pay damages if certain performance conditions are not met.
Leases
The Company has entered into operating leases for certain office facilities, compressors and office equipment. On January 1, 2019,In connection with the Chapter 11 Cases, the Company adopted ASC Topic 842, Leases, usingfiled a motion to reject its drilling rig contracts effective June 14, 2020. For one of the modified retrospective approach. Refer to Note 2—Basiscontracts, the rejection resulted in the removal of Presentation, Restatement, Significant Accounting Policiesthe lease liability and Recent Accounting Pronouncements, Leases for additional information.
net right-of-use asset in the amount of $6.9 million from the condensed consolidated balance sheets. Maturities of operating lease liabilities associated with ROUright-of-use assets and including imputed interest as of September 30, 2019, were as follows (in thousands):
| | | | | |
| Operating Leases |
| 2019 - remaining | $ | 2,956 | |
| 2020 | 8,675 | |
| 2021 | 3,340 | |
| 2022 | 2,211 | |
| 2023 | 2,246 | |
| Thereafter | 10,573 | |
| Total lease payments | 30,001 | |
Less imputed interest (1) | (3,938) | |
Present value of lease liabilities (2) | $ | 26,063 | |
| | | | | | | | | | | | | | | | | | | | |
| | As of June 30,
2020 | | | | As of December 31,
2019 |
| 2020 - remaining | | 3,635 | | | 2020 | | 19,040 | |
| 2021 | | 3,576 | | | 2021 | | 5,247 | |
| 2022 | | 2,211 | | | 2022 | | 2,211 | |
| 2023 | | 2,246 | | | 2023 | | 2,246 | |
| 2024 | | 2,301 | | | 2024 | | 2,301 | |
| Thereafter | | 8,273 | | | Thereafter | | 8,273 | |
| Total lease payments | | 22,242 | | | Total lease payments | | 39,318 | |
Less imputed interest (1) | | (3,191) | | | Less imputed interest (1) | | (4,735) | |
Present value of lease liabilities (2) | | $ | 19,051 | | | Present value of lease liabilities (2) | | $ | 34,583 | |
| | | | | | |
(1)Calculated using the estimated interest rate for each lease.
(2)Of the total present value of lease liabilities $9.2as of June 30, 2020 and December 31, 2019, $5.3 million wasand $17.4 thousand, respectively, were recorded in "Accountsaccounts payable and accrued liabilities"liabilities and $16.8$13.7 million wasand $17.2 thousand, respectively, were recorded in "Otherother non-current liabilities"liabilities on the condensed consolidated balance sheets.
As of December 31, 2018, minimum future contractual payments for operating leases under the scope of ASC 840 for certain office facilities and drilling rigs are as follows (in thousands):
| | | | | |
| Operating Leases |
| 2019 - remaining | $ | 12,713 | |
| 2020 | 3,371 | |
| 2021 | 3,385 | |
| 2022 | 3,360 | |
| 2023 | 3,411 | |
| Thereafter | 15,719 | |
| Total lease payments | $ | 41,959 | |
Drilling Rigs
As of SeptemberJune 30, 2019,2020, the Company was subject to commitments on 1 drilling rig contracted through November 2019.April 2021. These costs are capitalized within proved oil and gas properties on the condensed consolidated balance
sheets and are included as short-term lease costs in Note 2—Basiscosts. As part of Presentation, Restatement, Significant Accounting Policies and Recent Accounting Pronouncements, Leases. Beginning in November 2019,Chapter 11, the Company will befiled a motion to reject its drilling rig contract.As such, the Company recorded $6.7 million in liabilities subject to commitmentscompromise on one drilling rig contracted through February 2021. In the event of early termination of these contracts, the Company would be obligated to pay an aggregate amount of approximately $11.7 millioncondensed consolidated balance sheets as of SeptemberJune 30, 2019, as required under2020 and in reorganization items, net on the termscondensed consolidated statements of the contracts.operations.
Delivery Commitments
As part of September 30, 2019, the Chapter 11 Cases, the Company is currently in the process of renegotiating certain contracts terms which include minimum volume commitments. If mutual terms cannot be reached, the Company under Chapter 11 may file a motion to reject the contract.
The Company’s oil marketer was subject to a firm transportation agreement that commenced in November 2016 and hashad a ten-year term with a monthly minimum delivery commitment of 45,000 Bbl/d in year one, 55,800 Bbl/d in year two, 61,800 Bbl/d in years three through seven and 58,000 Bbl/d in years eight through ten. In May 2017, the Company amended its agreement with its oil marketer that requires it to sell all of its crude oil from an area of mutual interest in exchange for a make-whole provision that allowsallowed the Company to satisfy any minimum volume commitment deficiencies incurred by its oil marketer with future barrels of crude oil in excess of their minimum volume commitment during the contract term. In May 2019, the Company extended the term of this agreement through October 31, 2020 subject to an evergreen provision thereafter where either party can provide a six month notice of termination beginning November 1, 2020. Due to the contract termination date, the amount of consideration recognized in revenue is reduced. Please see Note 2—Basis of Presentation, Significant Accounting Policies and Recent Accounting Pronouncements — Revenue — Contract Balances. On June 12, 2020, the Company and the contract counterparty mutually terminated its contract with the Company's oil marketer effective June 30, 2020. The Company had received $35.7 million in cash in excess of barrels delivered through June 30, 2020. As such, this amount became due and was reclassified to current liabilities within accounts payable and accrued liabilities in the Company's condensed consolidated balance sheets. The Company has posted a letter of credit for this agreement in the amount of $40.0 million. On August 6, 2020, the counterparty drew $23.2 million on the letter of credit.
After cancellation of the aforementioned contract, the Company now has a long-term crude oil delivery commitment agreement that will commence on July 1, 2020. As of June 30, 2020, the Company's long-term crude oil delivery commitment has a monthly minimum delivery commitment of 61,800 Bbl/d through October 2023 and reduced to 58,000 Bbl/d through October 2026. The Company is required to pay a shortfall fee for any volume deficiencies under
these commitments. The aggregate remaining amount of estimated payments under these agreements is approximately $631.8 million.
The Company has two2 long-term crude oil gathering commitments with an unconsolidated subsidiary, in which the Company hashad a minority ownership interest,interest. Please see Note 1—Business and Organization for information related to the deconsolidation of Elevation Midstream, LLC. The first agreement commenced in November 2016 and has a term of ten years with a minimum volume commitment of an average of 9,167 Bbl/d in year one, 17,967 Bbl/d in year two, 18,800 Bbl/d for years three through five and 10,000 Bbl/d for years six through ten. The Company may be required to pay a shortfall fee for any volume deficiencies under this commitment. The second agreement commenced in July 2019 and has a term of ten years for an average of 3,200 Bbl/d in year one, 8,000 Bbl/d in year two, 14,000 Bbl/d in year three, 16,000 Bbl/d in years four through eight, 12,000 Bbl/d in year nine and 10,000 Bbl/d in year ten. The Company may be required to pay a shortfall fee for any volume deficiencies under this commitment. The aggregate remaining amount of estimated payments under these agreements is approximately $114.9 million.
In February 2019, the Company entered into two long-term gas gathering and processing agreements with third-party midstream providers. One of the agreements additionally includes a long-term NGL sales commitment for take-in-kind NGLs from other processing agreements. The first agreement commenced in November 2019 and has a term of twenty years with a third party midstream provider. minimum volume commitment of 251 Bcf to be delivered within the first seven years. The annual commitments over seven years are to be delivered on an average 85,000 Mcf/d in year one, 125,000 Mcf/d in year two, 140,000 Mcf/d in year three, 118,000 Mcf/d in year four, 98,000 Mcf/d in year five, 70,000 Mcf/d in year six and 52,000 Mcf/d in year seven. The aggregate remaining amount of estimated payments under this agreement is approximately $290.1 million. The second agreement commenced on January 2020 and has a term of ten years with an annual minimum volume commitment of 13.0 Bcf in years one through ten. The second agreement also includes a commitment to sell take-in-kind NGLs of 4,000 Bbl/d in year one and 7,500 Bbl/d in years two through seven with the ability to roll up to a 10% shortfall in a given month to the subsequent month.
The summary of these minimum volume commitments as of SeptemberJune 30, 2019,2020, was as follows:
| | | Oil (MBbl) | | Gas (MMcf) | | Total (MBOE) | | Oil (MBbl) | | Gas (MMcf) | | Total (MBOE) |
| 2019 - Remaining | 2,024 | | | 5,185 | | | 2,888 | | |
| 2020 | 8,935 | | | 33,550 | | | 14,527 | | |
| 2020 - remaining | | 2020 - remaining | 4,490 | | | 18,080 | | | 7,503 | |
| 2021 | 2021 | 10,349 | | | 46,540 | | | 18,106 | | 2021 | 9,797 | | | 46,540 | | | 17,554 | |
| 2022 | 2022 | 9,128 | | | 49,758 | | | 17,421 | | 2022 | 8,944 | | | 49,758 | | | 17,237 | |
| 2023 | 2023 | 9,490 | | | 41,850 | | | 16,465 | | 2023 | 9,490 | | | 41,850 | | | 16,465 | |
| 2024 | | 2024 | 9,516 | | | 34,160 | | | 15,209 | |
| Thereafter | Thereafter | 38,824 | | | 74,420 | | | 51,227 | | Thereafter | 29,860 | | | 40,260 | | | 36,570 | |
| Total | Total | 78,750 | | | 251,303 | | | 120,634 | | Total | 72,097 | | | 230,648 | | | 110,538 | |
The aggregate amount of estimated remaining payments under these agreements is $437.8 million.
Also, inIn collaboration with several other producers and a midstream provider, on December 15, 2016 and August 7, 2017, the Company agreed to participate in expansions of natural gas gathering and processing capacity in the DJ Basin. The plan includes 2 new processing plants as well as the expansion of related gathering systems. The first plant commenced operations in August 2018 and the second plant commenced operations in July 2019. The Company’s share of these commitments will require an incremental 51.5 and 20.6 MMcf per day, respectively, over a baseline volume of 65 MMcf per day to be delivered after the plants' in-service dates for a period of seven years thereafter. The Company may be required to pay a shortfall fee for any volumesincremental volume deficiency under these commitments. These contractual obligations can be reduced by the Company’s proportionate share of the collective volumes delivered to the plants by other third-party incremental volumes available to the midstream provider at the new facilities that are in excess of the total commitments. The Company is also required for the first three years of each contract to guarantee a certain target profit margin on these volumes sold. The Company also has a long-term gas gathering agreement with a third party midstream provider that will commence in or around January 2020 and has a term of ten years with an annual minimum volume commitment of 13.0 Bcf in years one through ten. We may be required to pay an annual shortfall fee for any volume deficiencies under this commitment, calculated based on the weighted average sales price during the corresponding annual period. Under its current drilling plans, the Company expects to meet these volume commitments.
In July 2019, the Company entered into 3 long-term contracts to supply 125,000 dekatherms of residue gas per day for five years to a transportation company. While our production is expected to satisfy these contracts, the aggregate remaining amount of estimated commitment assuming no production is $34.5$29.3 million. The Company has posted a letter of credit for this agreement in the amount of $8.7 million.
The Company is considering rejecting certain minimum volume commitments as part of the Chapter 11 Cases. The aggregate remaining amount of estimated remaining payments under these agreements is $1,066.1 million.
Elevation Gathering Agreements
In July 2018, the Company entered into three long-term gathering agreements (the "Elevation Gathering Agreements") for gas, crude oil and produced water with Elevation. Under the agreements, the Company agreed to drill 100 wells in Broomfield and 325 wells in Hawkeye by December 31, 2023 if both facilities are to be built, subject to adjustments if less capital is spent. Elevation has alleged that if the Company fails to complete the wells by the applicable commitment deadline, then it would be in breach of the agreement and Elevation could attempt to assert damages against Extraction and its affiliates. During the first quarter of 2020, Elevation postponed indefinitely further development of gathering systems and facilities that were to be constructed to service the Company's acreage in Hawkeye and another project in the Southwest Wattenberg area. Due to the decision to not complete the Hawkeye facilities and based on the amount of capital invested, Elevation has asserted that the drilling commitment now consists of 297 wells in the Broomfield area of operations with a deadline of December 31, 2022.
In April 2019, the Elevation Gathering Agreements were amended to provide for, among other amendments, the inclusion of additional gathering facilities in Elevation’s Badger facility. Pursuant to this amendment, Elevation has asserted that the additional gathering facilities were required to be completed by April 1, 2020 or, within 30 days of such date, Elevation could assert that Extraction must make a payment to Elevation in the amount of 135% of all costs incurred by Elevation as of such date for the development and construction of such additional gathering facilities. As of June 30, 2020, the costs incurred by Elevation for these additional gathering facilities totaled $34.7 million. The Company did not complete these additional gathering facilities by April 1, 2020, and Elevation has alleged that Extraction is in breach of the Elevation Gathering Agreements. On April 2, 2020, Elevation demanded payment of $46.8 million due to an alleged breach in contract stemming from a purported failure to complete the pipeline extensions connecting certain wells to the Badger central gathering facility prior to April 1, 2020. While the Company disputes that these amounts are due to Elevation, under ASC Topic 450 - Contingencies, the Company recorded the amount in liabilities subject to compromise on the condensed consolidated balance sheet as of June 30, 2020 and in other operating expenses on the condensed consolidated statements of operations.
In December 2019, the Elevation Gathering Agreements were further amended to provide Elevation additional connection fees that are consistent with market terms (the "Connect Fees"). In the fourth quarter of 2019, the Company incurred and paid $19.5 million for Connect Fees pursuant to the Elevation Gathering Agreements, and in the first quarter of 2020 the Company incurred and paid $23.5 million. The Company does not expect to incur additional Connect Fees for the year ending December 31, 2020.
In March 2020, the Elevation Gathering Agreements were further amended to reset all gathering rates and eliminate existing minimum drilling commitment. This amendment will not become effective until after all Elevation Preferred Units have been redeemed in full or are otherwise no longer outstanding.
Litigation and Legal Items
The Company is involved in various legal proceedings and reviews the status of these proceedings on an ongoing basis and, from time to time, may settle or otherwise resolve these matters on terms and conditions that management believes are in the Company’s best interests. The Company has provided the necessary estimated accruals in the condensed consolidated balance sheets where deemed appropriate for litigation and legal related items that are ongoing and not yet concluded. Although the results cannot be known with certainty, the Company currently believes that the ultimate results of such proceedings will not have a material adverse effect on our business, financial position, results of operations or liquidity.
Environmental. Due to the nature of the natural gas and oil industry, the Company is exposed to environmental risks. The Company has various policies and procedures to minimize and mitigate the risks from environmental contamination or with respect to environmental compliance issues. Liabilities are recorded when environmental damages resulting from past events are probable and the costs can be reasonably estimated. Except as discussed herein, the Company is not aware of any material environmental claims existing as of SeptemberJune 30, 20192020 which have not been provided for or would otherwise have a material impact on our financial statements; however, there can be no assurance that
current regulatory requirements will not change or that unknown potential past non-compliance with environmental laws, compliance matters or other environmental liabilities will not be discovered on our properties. Accrued environmental liabilities are recorded in accounts payable and accrued liabilities on the condensed consolidated balance sheets. The liability ultimately incurred with respect to a matter may exceed the related accrual.
Colorado Bradenhead Testing Matter. In February 2019, the Company resolved by an administrative order by consent (“AOC”) with the Colorado Oil and Gas Conservation Commission ("COGCC") administrative claims for allegations of noncompliance of State bradenhead testing rules at six pad sites in Weld County, Colorado. The AOC includes an administrative penalty of $0.8 million, of which $0.7 million of the total penalty is to be offset by our commensurate contribution to a public project and our requirement to undertake the required testing and improvements to the Company’s standard operating procedures. The Company has concluded that the resolution of this action did not have a material adverse effect on our financial position, results of operations or cash flows.
COGCC Notices of Alleged Violations (“NOAVs”). The Company has received NOAVs from the COGCC for alleged compliance violations that the Company has responded to. At this time, the COGCC has not alleged any specific penalty amounts in these matters. The Company does not believe that any penalties that could result from these NOAVs will have a material effect on our business, financial condition, results of operations or liquidity, but they may exceed $100,000.
Midstream Connections. The Company had dedicated the production from some acreage to a certain midstream service provider. However, the Company was unable to connect well pads to the provider due to the inability to secure right of way access for building the connection pipeline. Because the acreage’s production was dedicated to the midstream provider, they have invoiced the Company for oil and gas handled by other midstream providers. The Company disputes these invoices based on force majeure and may have other contractual or legal defenses. The Company’s maximum exposure as of June 30, 2020 was $17.9 million. As of June 30, 2020, no contingent liability has been recorded as it is not probable a loss has been incurred, and the amount of the loss cannot be reasonably estimated.
Elevation Gathering. As discussed above under Elevation Gathering Agreements, on April 2, 2020, Elevation demanded payment of $46.8 million due to an alleged breach in contract stemming from a purported failure to complete the pipeline extensions connecting certain wells to the Badger central gathering facility prior to April 1, 2020. While the Company disputes that these amounts are due to Elevation, under ASC Topic 450 - Contingencies, the Company recorded the amount in liabilities subject to compromise on the condensed consolidated balance sheet as of June 30, 2020 and in other operating expenses on the condensed consolidated statements of operations.
Note 12—15—Related Party Transactions
Office Lease with Affiliate of a Director2024 Senior Notes
In April 2016,Several 5% stockholders of the Company subleased office space to Star Peak Capital, LLC, of which a memberwere also holders of the board2024 Senior Notes. As of directors is an owner, for $1,400 per month. The sublease commencedthe initial issuance in August 2017 of the $400.0 million principal amount on May 1, 2016 and expires on February 28, 2020.the 2024 Senior Notes, such stockholders held $54.9 million.
2026 Senior Notes
Several holders of the 2026 Senior Notes are also 5% stockholders of the Company. As of the initial issuance in January 2018 of the $750.0 million principal amount on the 2026 Senior Notes, such stockholders held $56.2 million.
Elevation Midstream, LLC
As discussed in Note 14—Commitments and Contingencies, on April 2, 2020, Elevation demanded payment of $46.8 million due to an alleged breach in contract stemming from a purported failure to complete the pipeline extensions connecting certain wells to the Badger central gathering facility prior to April 1, 2020. While the Company disputes that these amounts are due to Elevation, under ASC Topic 450 - Contingencies, the Company recorded the amount in liabilities subject to compromise on the condensed consolidated balance sheet as of June 30, 2020 and in other operating expenses on the condensed consolidated statements of operations.
Note 13—16—Segment Information
Beginning in the fourth quarter of 2018, the Company hashad 2 operating segments, (i) the exploration, development and production of oil, natural gas and NGL (the "exploration and production segment") and (ii) the construction of and support of midstream assets to gather and process crude oil and gas production (the "gathering and facilities segment"). Prior toElevation Midstream, LLC comprised the fourth quarter of 2018, the Company had a single operating segment. The gathering systems and facilities operating segment was under development as of Septembersegment. During the three and six months ending June 30, 2019. Capital expenditures associated with gathering systems and facilities are being incurred to develop midstream infrastructure to support2019, the Company's development of its oil and gas leasehold along with third-party activity.
The Company's exploration and production segment revenues are derived from third parties. The Company’s gathering and facilities segment was in the construction phase and no revenue generating activities had commenced ascommenced. Through March 16, 2020, the results of September 30, 2019; however, on October 3, 2019, Elevation commenced moving crude oil, natural gas and water through its Badger central gathering facility.
Financial informationwere included in the consolidated financial statements of Extraction. Effective March 17, 2020, the Company's reportable segments was as follows for the three months ended September 30, 2019 and 2018 (in thousands).
| | | | | | | | | | | | | | | | | | | | | | | |
| For the Three Months Ended September 30, 2019 | | | | | | |
| Exploration and Production | | Gathering and Facilities | | Elimination of Intersegment Transactions | | Consolidated Total |
| As restated | | | | | | As restated |
| Revenues: | | | | | | | |
| Revenues from external customers | $ | 176,942 | | | $ | — | | | $ | — | | | $ | 176,942 | |
| Intersegment revenues | — | | | — | | | — | | | — | |
| Total Revenues | $ | 176,942 | | | $ | — | | | $ | — | | | $ | 176,942 | |
| | | | | | | |
| Operating Expenses and Other Income (Expense): | | | | | | | |
| Depletion, depreciation, amortization and accretion | $ | (114,971) | | | $ | (25) | | | $ | — | | | $ | (114,996) | |
| Interest income | 114 | | | 355 | | | — | | | 469 | |
| Interest expense | (23,224) | | | — | | | — | | | (23,224) | |
| Earnings in unconsolidated subsidiaries | — | | | 640 | | | — | | | 640 | |
| Subtotal Operating Expenses and Other Income (Expense): | $ | (138,081) | | | $ | 970 | | | $ | — | | | $ | (137,111) | |
| | | | | | | |
| Segment Assets | $ | 4,046,862 | | | $ | 395,224 | | | $ | (619) | | | $ | 4,441,467 | |
| Capital Expenditures | $ | 134,998 | | | $ | 65,098 | | | $ | — | | | $ | 200,096 | |
| Investment in Equity Method Investees | $ | — | | | $ | 35,992 | | | $ | — | | | $ | 35,992 | |
| Segment EBITDAX | $ | 138,491 | | | $ | (622) | | | $ | — | | | $ | 137,869 | |
| | | | | | | | | | | | | | | | | | | | | | | |
| For the Three Months Ended September 30, 2018 | | | | | | |
| Exploration and Production | | Gathering and Facilities | | Elimination of Intersegment Transactions | | Consolidated Total |
| Revenues: | | | | | | | |
| Revenues from external customers | $ | 282,160 | | | $ | — | | | $ | — | | | $ | 282,160 | |
| Intersegment revenues | — | | | — | | | — | | | — | |
| Total Revenues | $ | 282,160 | | | $ | — | | | $ | — | | | $ | 282,160 | |
| | | | | | | |
| Operating Expenses and Other Income (Expense): | | | | | | | |
| Depletion, depreciation, amortization and accretion | $ | (107,315) | | | $ | — | | | $ | — | | | $ | (107,315) | |
| Interest income | 135 | | | 635 | | | — | | | 770 | |
| Interest expense | (20,725) | | | — | | | — | | | (20,725) | |
| Earnings in unconsolidated subsidiaries | — | | | 843 | | | — | | | 843 | |
| Subtotal Operating Expenses and Other Income (Expense): | $ | (127,905) | | | $ | 1,478 | | | $ | — | | | $ | (126,427) | |
| | | | | | | |
| Segment Assets | $ | 3,894,535 | | | $ | 264,014 | | | $ | (224) | | | $ | 4,158,325 | |
| Capital Expenditures | $ | 202,811 | | | $ | 37,548 | | | $ | — | | | $ | 240,359 | |
| Investment in Equity Method Investees | $ | — | | | $ | 14,510 | | | $ | — | | | $ | 14,510�� | |
| Segment EBITDAX | $ | 170,004 | | | $ | (601) | | | $ | — | | | $ | 169,403 | |
Financial information of the Company's reportable segments was as follows for the nine months ended September 30, 2019 and 2018 (in thousands).
| | | | | | | | | | | | | | | | | | | | | | | |
| For the Nine Months Ended September 30, 2019 | | | | | | |
| Exploration and Production | | Gathering and Facilities | | Elimination of Intersegment Transactions | | Consolidated Total |
| As restated | | | | | | As restated |
| Revenues: | | | | | | | |
| Revenues from external customers | $ | 620,916 | | | $ | — | | | $ | — | | | $ | 620,916 | |
| Intersegment revenues | — | | | — | | | — | | | — | |
| Total Revenues | $ | 620,916 | | | $ | — | | | $ | — | | | $ | 620,916 | |
| | | | | | | |
| Operating Expenses and Other Income (Expense): | | | | | | | |
| Depletion, depreciation, amortization and accretion | $ | (352,062) | | | $ | (72) | | | $ | — | | | $ | (352,134) | |
| Interest income | 372 | | | 1,286 | | | — | | | 1,658 | |
| Interest expense | (54,791) | | | — | | | — | | | (54,791) | |
| Earnings in unconsolidated subsidiaries | — | | | 1,179 | | | — | | | 1,179 | |
| Subtotal Operating Expenses and Other Income (Expense): | $ | (406,481) | | | $ | 2,393 | | | $ | — | | | $ | (404,088) | |
| | | | | | | |
| Segment Assets | $ | 4,046,862 | | | $ | 395,224 | | | $ | (619) | | | $ | 4,441,467 | |
| Capital Expenditures | $ | 516,510 | | | $ | 192,568 | | | $ | — | | | $ | 709,078 | |
| Investment in Equity Method Investees | $ | — | | | $ | 35,992 | | | $ | — | | | $ | 35,992 | |
| Segment EBITDAX | $ | 406,539 | | | $ | (1,168) | | | $ | — | | | $ | 405,371 | |
| | | | | | | | | | | | | | | | | | | | | | | |
| For the Nine Months Ended September 30, 2018 | | | | | | |
| Exploration and Production | | Gathering and Facilities | | Elimination of Intersegment Transactions | | Consolidated Total |
| Revenues: | | | | | | | |
| Revenues from external customers | $ | 772,571 | | | $ | — | | | $ | — | | | $ | 772,571 | |
| Intersegment revenues | — | | | — | | | — | | | — | |
| Total Revenues | $ | 772,571 | | | $ | — | | | $ | — | | | $ | 772,571 | |
| | | | | | | |
| Operating Expenses and Other Income (Expense): | | | | | | | |
| Depletion, depreciation, amortization and accretion | $ | (310,296) | | | $ | — | | | $ | — | | | $ | (310,296) | |
| Interest income | 280 | | | 635 | | | — | | | 915 | |
| Interest expense | (103,229) | | | — | | | — | | | (103,229) | |
| Earnings in unconsolidated subsidiaries | — | | | 1,567 | | | — | | | 1,567 | |
| Subtotal Operating Expenses and Other Income (Expense): | $ | (413,245) | | | $ | 2,202 | | | $ | — | | | $ | (411,043) | |
| | | | | | | |
| Segment Assets | $ | 3,894,535 | | | $ | 264,014 | | | $ | (224) | | | $ | 4,158,325 | |
| Capital Expenditures | $ | 730,878 | | | $ | 57,224 | | | $ | — | | | $ | 788,102 | |
| Investment in Equity Method Investees | $ | — | | | $ | 14,510 | | | $ | — | | | $ | 14,510 | |
| Segment EBITDAX | $ | 463,415 | | | $ | 102 | | | $ | — | | | $ | 463,517 | |
The following table presents a reconciliation of Adjusted EBITDAX by segment to the GAAP financial measure of income (loss) before income taxes for the three and ninesix months ended SeptemberJune 30, 20192020 and 20182019 (in thousands).
| | | For the Three Months Ended September 30, | | | For the Nine Months Ended September 30, | | | For the Three Months Ended June 30, | | | For the Six Months Ended June 30, | |
| | 2019 | | 2018 | | 2019 | | 2018 | | 2020 | | 2019 | | 2020 | | 2019 |
| As restated | | As restated | | | |
| Reconciliation of Adjusted EBITDAX to Income Before Income Taxes | | |
| Reconciliation of Adjusted EBITDAX to Income (Loss) Before Income Taxes | | Reconciliation of Adjusted EBITDAX to Income (Loss) Before Income Taxes | | | | | | | |
| Exploration and production segment EBITDAX | Exploration and production segment EBITDAX | $ | 138,491 | | | $ | 170,004 | | | $ | 406,539 | | | $ | 463,415 | | Exploration and production segment EBITDAX | $ | 114,039 | | | $ | 129,534 | | | $ | 236,679 | | | $ | 268,045 | |
| Gathering and facilities segment EBITDAX | Gathering and facilities segment EBITDAX | (622) | | | (601) | | | (1,168) | | | 102 | | Gathering and facilities segment EBITDAX | — | | | (223) | | | 1,256 | | | (547) | |
| Subtotal of Reportable Segments | Subtotal of Reportable Segments | $ | 137,869 | | | $ | 169,403 | | | $ | 405,371 | | | $ | 463,517 | | Subtotal of Reportable Segments | $ | 114,039 | | | $ | 129,311 | | | $ | 237,935 | | | $ | 267,498 | |
| Less: | Less: | | Less: | |
| Depletion, depreciation, amortization and accretion | Depletion, depreciation, amortization and accretion | $ | (114,996) | | | $ | (107,315) | | | $ | (352,134) | | | $ | (310,296) | | Depletion, depreciation, amortization and accretion | $ | (82,620) | | | $ | (118,368) | | | $ | (158,670) | | | $ | (237,138) | |
| Impairment of long lived assets | Impairment of long lived assets | — | | | (16,166) | | | (11,233) | | | (16,294) | | Impairment of long lived assets | (960) | | | (2,985) | | | (1,736) | | | (11,233) | |
| Exploration expenses | (13,245) | | | (11,038) | | | (32,725) | | | (21,326) | | |
| Gain on sale of property and equipment and assets of unconsolidated subsidiary | 1,011 | | | 83,559 | | | 1,329 | | | 143,461 | | |
| Other operating expenses | | Other operating expenses | (13,209) | | | — | | | (65,784) | | | — | |
| Exploration and abandonment expenses | | Exploration and abandonment expenses | (62,661) | | | (13,287) | | | (175,141) | | | (19,481) | |
| Gain on sale of property and equipment | | Gain on sale of property and equipment | — | | | 97 | | | — | | | 319 | |
| Gain (loss) on commodity derivatives | Gain (loss) on commodity derivatives | 87,956 | | | (35,913) | | | 39,383 | | | (175,752) | | Gain (loss) on commodity derivatives | (69,301) | | | 73,519 | | | 193,714 | | | (48,572) | |
| Settlements on commodity derivative instruments | Settlements on commodity derivative instruments | (16,101) | | | 41,009 | | | 8,432 | | | 99,914 | | Settlements on commodity derivative instruments | (127,429) | | | 14,203 | | | (166,725) | | | 24,532 | |
| Premiums paid for derivatives that settled during the period | Premiums paid for derivatives that settled during the period | 812 | | | 1,956 | | | 19,910 | | | 5,191 | | Premiums paid for derivatives that settled during the period | — | | | 9,549 | | | — | | | 19,098 | |
| Stock-based compensation expense | Stock-based compensation expense | (11,358) | | | (17,420) | | | (39,306) | | | (50,883) | | Stock-based compensation expense | (2,560) | | | (14,937) | | | (2,560) | | | (27,945) | |
| Amortization of debt issuance costs | Amortization of debt issuance costs | (974) | | | (935) | | | (3,799) | | | (12,303) | | Amortization of debt issuance costs | (1,948) | | | (1,328) | | | (3,190) | | | (2,826) | |
| Make-whole premium on 2021 Senior Notes | — | | | — | | | — | | | (35,600) | | |
| Gain on repurchase of 2026 Senior Notes | Gain on repurchase of 2026 Senior Notes | — | | | — | | | 10,486 | | | — | | Gain on repurchase of 2026 Senior Notes | — | | | 3,169 | | | — | | | 10,486 | |
| Interest expense | Interest expense | (22,250) | | | (19,790) | | | (61,478) | | | (55,326) | | Interest expense | (18,366) | | | (20,399) | | | (38,482) | | | (39,226) | |
| Loss on deconsolidation of investment | | Loss on deconsolidation of investment | — | | | — | | | (73,139) | | | — | |
| Reorganization items, net | | Reorganization items, net | (26,919) | | | — | | | (26,919) | | | — | |
| Income (Loss) Before Income Taxes | Income (Loss) Before Income Taxes | $ | 48,724 | | | $ | 87,350 | | | $ | (15,764) | | | $ | 34,303 | | Income (Loss) Before Income Taxes | $ | (291,934) | | | $ | 58,544 | | | $ | (280,697) | | | $ | (64,488) | |
Financial information of the Company's reportable segments was as follows for the three months ended June 30, 2020 and 2019 (in thousands).
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | For the Three Months Ended June 30, 2020 | | | | | | |
| | | | | | | | | | Exploration and Production | | Gathering and Facilities | | Elimination of Intersegment Transactions | | Consolidated Total |
| Revenues: | | | | | | | | | | | | | | | | |
| Revenues from third parties | | | | | | | | | | $ | 63,129 | | | $ | — | | | $ | — | | | $ | 63,129 | |
| Revenues from Extraction | | | | | | | | | | — | | | — | | | — | | | — | |
| Total Revenues | | | | | | | | | | $ | 63,129 | | | $ | — | | | $ | — | | | $ | 63,129 | |
| | | | | | | | | | | | | | | | |
| Operating Expenses and Other Income (Expense): | | | | | | | | | | | | | | | | |
| Direct operating expenses | | | | | | | | | | $ | (53,969) | | | $ | — | | | $ | — | | | $ | (53,969) | |
| Depletion, depreciation, amortization and accretion | | | | | | | | | | (82,620) | | | — | | | — | | | (82,620) | |
| Interest income | | | | | | | | | | 10 | | | — | | | — | | | 10 | |
| Interest expense | | | | | | | | | | (20,314) | | | — | | | — | | | (20,314) | |
| Earnings in unconsolidated subsidiaries | | | | | | | | | | — | | | — | | | — | | | — | |
| Subtotal Operating Expenses and Other Income (Expense): | | | | | | | | | | $ | (156,893) | | | $ | — | | | $ | — | | | $ | (156,893) | |
| | | | | | | | | | | | | | | | |
| Segment Assets | | | | | | | | | | $ | 2,404,356 | | | $ | — | | | $ | — | | | $ | 2,404,356 | |
| Capital Expenditures | | | | | | | | | | 14,261 | | | — | | | — | | | 14,261 | |
| Investment in Equity Method Investees | | | | | | | | | | — | | | — | | | — | | | — | |
| Segment EBITDAX | | | | | | | | | | 114,039 | | | — | | | — | | | 114,039 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | For the Three Months Ended June 30, 2019 | | | | | | |
| | | | | | | | | | Exploration and Production | | Gathering and Facilities | | Elimination of Intersegment Transactions | | Consolidated Total |
| Revenues: | | | | | | | | | | | | | | | | |
| Revenues from third parties | | | | | | | | | | $ | 222,057 | | | $ | — | | | $ | — | | | $ | 222,057 | |
| Revenues from Extraction | | | | | | | | | | — | | | — | | | — | | | — | |
| Total Revenues | | | | | | | | | | $ | 222,057 | | | $ | — | | | $ | — | | | $ | 222,057 | |
| | | | | | | | | | | | | | | | |
| Operating Expenses and Other Income (Expense): | | | | | | | | | | | | | | | | |
| Direct operating expenses | | | | | | | | | | $ | — | | | $ | — | | | $ | — | | | $ | — | |
| Depletion, depreciation, amortization and accretion | | | | | | | | | | (118,340) | | | (28) | | | — | | | (118,368) | |
| Interest income | | | | | | | | | | 104 | | | 306 | | | — | | | 410 | |
| Interest expense | | | | | | | | | | (18,558) | | | — | | | — | | | (18,558) | |
| Earnings in unconsolidated subsidiaries | | | | | | | | | | — | | | 239 | | | — | | | 239 | |
| Subtotal Operating Expenses and Other Income (Expense): | | | | | | | | | | $ | (136,794) | | | $ | 517 | | | $ | — | | | $ | (136,277) | |
| | | | | | | | | | | | | | | | |
| Segment Assets | | | | | | | | | | $ | 3,966,523 | | | $ | 286,550 | | | $ | (524) | | | $ | 4,252,549 | |
| Capital Expenditures | | | | | | | | | | 222,890 | | | 68,607 | | | — | | | 291,497 | |
| Investment in Equity Method Investees | | | | | | | | | | — | | | 27,826 | | | — | | | 27,826 | |
| Segment EBITDAX | | | | | | | | | | 129,534 | | | (223) | | | — | | | 129,311 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | For the Six Months Ended June 30, 2020 | | | | | | |
| | | | | | | | | | Exploration and Production | | Gathering and Facilities | | Elimination of Intersegment Transactions | | Consolidated Total |
| Revenues: | | | | | | | | | | | | | | | | |
| Revenues from third parties | | | | | | | | | | $ | 226,843 | | | $ | 1,473 | | | $ | — | | | $ | 228,316 | |
| Revenues from Extraction | | | | | | | | | | — | | | 4,513 | | | (4,513) | | | — | |
| Total Revenues | | | | | | | | | | $ | 226,843 | | | $ | 5,986 | | | $ | (4,513) | | | $ | 228,316 | |
| | | | | | | | | | | | | | | | |
| Operating Expenses and Other Income (Expense): | | | | | | | | | | | | | | | | |
| Direct operating expenses | | | | | | | | | | $ | (124,893) | | | $ | (3,935) | | | $ | 4,294 | | | $ | (124,534) | |
| Depletion, depreciation, amortization and accretion | | | | | | | | | | (157,571) | | | (1,099) | | | — | | | (158,670) | |
| Interest income | | | | | | | | | | 70 | | | 29 | | | — | | | 99 | |
| Interest expense | | | | | | | | | | (41,672) | | | — | | | — | | | (41,672) | |
| Earnings in unconsolidated subsidiaries | | | | | | | | | | — | | | 480 | | | — | | | 480 | |
| Subtotal Operating Expenses and Other Income (Expense): | | | | | | | | | | $ | (324,066) | | | $ | (4,525) | | | $ | 4,294 | | | $ | (324,297) | |
| | | | | | | | | | | | | | | | |
| Segment Assets | | | | | | | | | | $ | 2,404,356 | | | $ | — | | | $ | — | | | $ | 2,404,356 | |
| Capital Expenditures | | | | | | | | | | 169,702 | | | (6,311) | | | — | | | 163,391 | |
| Investment in Equity Method Investees | | | | | | | | | | — | | | — | | | — | | | — | |
| Segment EBITDAX | | | | | | | | | | 236,679 | | | 1,256 | | | — | | | 237,935 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | For the Six Months Ended June 30, 2019 | | | | | | |
| | | | | | | | | | Exploration and Production | | Gathering and Facilities | | Elimination of Intersegment Transactions | | Consolidated Total |
| Revenues: | | | | | | | | | | | | | | | | |
| Revenues from third parties | | | | | | | | | | $ | 443,974 | | | $ | — | | | $ | — | | | $ | 443,974 | |
| Revenues from Extraction | | | | | | | | | | — | | | — | | | — | | | — | |
| Total Revenues | | | | | | | | | | $ | 443,974 | | | $ | — | | | $ | — | | | $ | 443,974 | |
| | | | | | | | | | | | | | | | |
| Operating Expenses and Other Income (Expense): | | | | | | | | | | | | | | | | |
| Direct operating expenses | | | | | | | | | | $ | — | | | $ | — | | | $ | — | | | $ | — | |
| Depletion, depreciation, amortization and accretion | | | | | | | | | | (237,091) | | | (47) | | | — | | | (237,138) | |
| Interest income | | | | | | | | | | 258 | | | 931 | | | — | | | 1,189 | |
| Interest expense | | | | | | | | | | (31,566) | | | — | | | — | | | (31,566) | |
| Earnings in unconsolidated subsidiaries | | | | | | | | | | — | | | 404 | | | — | | | 404 | |
| Subtotal Operating Expenses and Other Income (Expense): | | | | | | | | | | $ | (268,399) | | | $ | 1,288 | | | $ | — | | | $ | (267,111) | |
| | | | | | | | | | | | | | | | |
| Segment Assets | | | | | | | | | | $ | 3,966,523 | | | $ | 286,550 | | | $ | (524) | | | $ | 4,252,549 | |
| Capital Expenditures | | | | | | | | | | 381,512 | | | 127,470 | | | — | | | 508,982 | |
| Investment in Equity Method Investees | | | | | | | | | | — | | | 27,826 | | | — | | | 27,826 | |
| Segment EBITDAX | | | | | | | | | | 268,045 | | | (547) | | | — | | | 267,498 | |
ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
As discussed in Note 2—Basis of Presentation, Restatement, Significant Accounting Policies and Recent Accounting Pronouncements to the condensed consolidated financial statements, the Company has restated its financial statements as of and for the three and nine months ended September 30, 2019, and the following information reflects the impact of that restatement.
CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS
This Quarterly Report on Form 10-Q (“Quarterly Report”) contains "forward-looking statements." All statements, other than statements of historical facts, included or incorporated by reference herein concerning, among other things, planned capital expenditures, increases in oil and gas production, the number of anticipated wells to be drilled or completed after the date hereof, future cash flows and borrowings, pursuit of potential acquisition opportunities, our financial position, business strategy and other plans and objectives for future operations, are forward-looking statements. These forward-looking statements are identified by their use of terms and phrases such as ''may," "expect," "estimate," "project," "plan," "believe," "intend," "achievable," "anticipate," ''will," "continue," ''potential," "should," "could," and similar terms and phrases. For such statements, we claim the protection of the safe harbor for forward-looking statements contained in the Private Securities Litigation Reform Act of 1995. Although we believe that the expectations reflected in these forward-looking statements are reasonable, they do involve certain assumptions, risks and uncertainties. Our results could differ materially from those anticipated in these forward-looking statements as a result of certain factors, including, among others:
•potential adverse effects of the Chapter 11 Cases on our liquidity and results of operations;
•objections to the confirmation of our Restructuring Plan or other pleadings we file that could protract the Chapter 11 Cases;
•our ability to continue as a going concern;
•our ability to comply with the restrictions and other covenants imposed by our DIP Credit Agreement and other financial arrangements;
•the Bankruptcy Court’s rulings in the Chapter 11 Cases, and the outcome of the Chapter 11 Cases generally;
•the length of time that we will operate under Chapter 11 protection and the continued availability of operating capital during the pendency of the proceedings;
•federal and state regulations and laws;
•capital requirements and uncertainty of obtaining additional funding on terms acceptable to us;
•risks and restrictions related to our debt agreements;
•our ability to use derivative instruments to manage commodity price risk;
•realized oil, natural gas and NGL prices;
•a decline in oil, natural gas and NGL production, and the impact of general economic conditions on the demand for oil, natural gas and NGL and the availability of capital;capital to oil and natural gas producers;
•asset impairments from commodity price declines;
•the outbreak of communicable diseases such as coronavirus;
•the willingness of the Organization of Petroleum Exporting Countries (“OPEC”) and certain other oil and natural gas producing countries to set and maintain production levels;
•unsuccessful drilling and completion activities and the possibility of resulting write-downs;
•geographical concentration of our operations;
•constraints in the DJ Basin of Colorado with respect to gathering, transportation and processing facilities and marketing;
•lack of U.S. domestic storage;
•our ability to meet our proposed drilling schedule and to successfully drill wells that produce oil or natural gas in commercially viable quantities;
•shortages of oilfield equipment, supplies, services and qualified personnel and increased costs for such equipment, supplies, services and personnel;
•adverse variations from estimates of reserves, production, production prices and expenditure requirements, and our inability to replace our reserves through exploration and development activities;
•incorrect estimates associated with properties we acquire relating to estimated proved reserves, the presence or recoverability of estimated oil and natural gas reserves and the actual future production rates and associated costs of such acquired properties;
•drilling operations associated with the employment of horizontal drilling techniques, and adverse weather and environmental conditions;
•limited control over non-operated properties;
•title defects to our properties and inability to retain our leases;
•our ability to successfully develop our large inventory of undeveloped operated and non-operated acreage;
•our ability to retain key members of our senior management and key technical employees;
•risks relating to managing our growth, particularly in connection with the integration of significant acquisitions;
•impact of environmental, health and safety, and other governmental regulations, and of current or pending legislation;
•risks associated with a material weakness in our internal control over financial reporting;
•changes in tax laws;
•effects of competition; and
•seasonal weather conditions.
Reserve engineering is a process of estimating underground accumulations of oil, natural gas, and NGL that cannot be measured in an exact way. The accuracy of any reserve estimate depends on the quality of available data, the interpretation of such data and price and cost assumptions made by reserve engineers and management. In addition, the results of drilling, testing and production activities may justify revisions of estimates that were made previously. If significant, such revisions would change the schedule of any further production and development drilling. Accordingly, reserve estimates may differ significantly from the quantities of oil, natural gas and NGL that are ultimately recovered.
In addition to the other information and risk factors set forth in this Quarterly Report, you should carefully consider the risk factors and other cautionary statements described under the heading “Risk Factors” included in Item 1A of this Quarterly Report on Form 10-Q and our Annual Report on Form 10-K for the year ended December 31, 20182019 (our “Annual Report”) and in our other filings with the Securities and Exchange Commission, which could materially affect our business, financial condition or future results. Additional risks and uncertainties not currently known to us or that we currently deem to be immaterial also may materially adversely affect our business, financial condition or future results. Other than as set forth in this Quarterly Report, there have been no material changes in our risk factors from those described in our Annual Report.
All forward-looking statements attributable to us or persons acting on our behalf are expressly qualified in their entirety by the cautionary statements in this section and elsewhere in this Quarterly Report. Except as required by law, we do not assume a duty to update these forward-looking statements, whether as a result of new information, subsequent events or circumstances, changes in expectations or otherwise.
Management’s Discussion and Analysis of Financial Condition and Results of Operations (“MD&A”) is intended to provide the reader of the financial statements with a narrative from the perspective of management on the financial condition, results of operations, liquidity and certain other factors that may affect the Company’s operating results. MD&A should be read in conjunction with the Condensed Consolidated Financial Statements and related Notes included in Part I, Item 1 of this Quarterly Report. The following information updates the discussion of the Company’s financial condition provided in itsour Annual Report and analyzes the changes in the results of operations between the three and ninesix months ended SeptemberJune 30, 20192020 and 2018.2019.
EXECUTIVE SUMMARY
We are an independent oil and gas company focused on the acquisition, development and production of oil, natural gas and NGL reserves, as well as the construction and support of midstream assets to gather crude oil, natural gas and water production in the Rocky Mountain region, primarily in the Wattenberg Field of the DJ Basin.Denver-Julesburg Basin of Colorado. We have developed an oil, natural gas and NGL asset base of proved reserves, as well as a portfolio of development drilling opportunities on high resource-potential leasehold on contiguous acreage blocks in some of the most productive areas of what we consider to be the core of the DJ Basin. We are focused on growing our proved reserves and production primarily through the development of our large inventory of identified liquids-rich horizontal drilling locations, as well as the design and support of midstream assets to gather and process crude oil and gas production focused in the DJ Basin.
Financial Results
For the three and ninesix months ended SeptemberJune 30, 2019,2020, crude oil, natural gas and NGL sales, coupled with the impact of settled derivatives, decreased to $192.3$94.5 million and $592.6$299.0 million, respectively, as compared to $239.2$198.3 million and $667.5$400.3 million, respectively, in the same prior year periodsperiod due to a decrease of $8.34$14.95 and $6.89$9.49, respectively, in realized price per BOE, respectively, including settled derivatives, partially offset by an increase in sales volumes of 427approximately 782 MBoe and 2,3122,123 MBoe, respectively.
For the three and ninesix months ended SeptemberJune 30, 2019,2020, we had net income of $33.9 million anda net loss of $16.7$291.9 million and $282.9 million, respectively, as compared to net income of $65.2$43.4 million and $22.0a net loss of $50.6 million, respectively, for the three and ninesix months ended SeptemberJune 30, 2018, respectively.2019. The change into a net loss for the three months ended June 30, 2020 from net income for the three months ended SeptemberJune 30, 2019 from the three months ended September 30, 2018 was primarily driven by a decrease in sales revenue of $105.2 million partially offset by an increase in commodity derivative gain of $123.9 million and an increase in operating expenses of $28.3 million excluding the gain on sale of property and equipment and assets of unconsolidated subsidiary of $82.5 million. The change to net loss for the
nine months ended September 30, 2019 from net income for the nine months ended September 30, 2018 was primarily driven by a decrease in sales revenues of $151.6$158.9 million, and a decrease in interest expensecommodity derivative gains of $48.4$142.8 million related to redemptionand an increase in operating expenses of $19.2 million, partially offset by a decrease in income tax expenses of $15.1 million. The increase in net loss for the Company's 2021 Senior Notes during the ninesix months ended SeptemberJune 30, 20182020 as compared to the six months ended June 30, 2019 was primarily driven by a decrease in sales revenues of $215.7 million, an increase in the loss from deconsolidation of $73.1 million and an increase in operating expenses of $131.3 million, partially offset by an increase in operating expenses of $162.2 million and an increase in the commodity derivative gaingains of $215.1$242.3 million.
Adjusted EBITDAX was $137.9$114.0 million and $405.4$237.9 million, respectively, for the three and ninesix months ended SeptemberJune 30, 2019, respectively,2020 as compared to $169.4$129.3 million and $463.5$267.5 million, respectively, for the three and ninesix months ended SeptemberJune 30, 2018, respectively,2019, reflecting a 18.6%11.8% decrease and an 12.5%a 11.1% decrease, respectively. Adjusted EBITDAX is a non-GAAP financial measure. For a definition of Adjusted EBITDAX and a reconciliation to our most directly comparable financial measure calculated and presented in accordance with GAAP, please readrefer to “—Adjusted EBITDAX.”
Operational Results
During the three months ended SeptemberJune 30, 2019, our aggregate drilling, completion, and leasehold capital expenditures, totaled $135.0 million, of which $122.3 million was2020, we implemented operational efficiencies to reduce drilling and completion additions and $12.7costs. We incurred approximately $12.0 million was leasehold and surface acreage additions. This excludes the impact of the decrease in outstanding elections of $3.9 million. In addition, Elevation Midstream, LLC, our wholly owned midstream subsidiary, incurred $65.1 million of capital expenditures during the three months ended September 30, 2019. These capital expenditures are funded entirely pursuant to the Elevation Midstream, LLC Securities Purchase Agreement.
During the three months ended September 30, 2019, we drilled 27drilling 3 gross (20.0 net) wells with an average length of approximately 10,900 feet and completed 37 gross (31.2(2.0 net) wells with an average lateral length of approximately 8,900 feet. We turned to sales 222.5 miles and completing 12 gross (17.7(7.8 net) wells with an average lateral length of 2.5 miles, all of which were horizontal wells in the DJ Basin. In addition, we incurred approximately 9,500 feet.$2.3 million of leasehold and surface acreage additions. During the three months ended June 30, 2019, we incurred approximately $210.2 million in drilling 33 gross (27.0 net) wells with an average lateral length of 1.8 miles and completing 36 gross (31.0 net) wells with an average lateral length of 1.9 miles, all of which were horizontal wells in the DJ Basin. In addition, we incurred approximately $12.6 million of leasehold and surface acreage additions.
During the six months ended June 30, 2020, we incurred approximately $158.6 million in drilling 37 gross (26.5 net) wells with an average lateral length of 2.3 miles and completing 41 gross (31.6 net) wells with an average lateral length of 2.4 miles, all of which were horizontal wells in the DJ Basin. In addition, we incurred approximately $11.1 million of leasehold and surface acreage additions. During the six months ended June 30, 2019, we incurred approximately $349.7 million in drilling 63 gross (53.0 net) wells with an average lateral length of 1.6 miles and completing 76 gross (66.0 net) wells with an average lateral length of 1.6 miles, all of which were horizontal wells in the DJ Basin. In addition, we incurred approximately $31.7 million of leasehold and surface acreage additions.
Recent Developments
Chapter 11 Cases
On June 14, 2020, we commenced voluntary cases under chapter 11 of the Bankruptcy Code. Also on June 14, 2020, we entered into a restructuring support agreement with certain holders of our Senior Notes to support a restructuring in accordance with the terms set forth therein. We expect to continue operations in the normal course for the duration of the Chapter 11 Cases. To ensure ordinary course operations, we have obtained approval from the Bankruptcy Court for certain “first day” motions, including motions to obtain customary relief intended to assure our ability to continue our ordinary course operations after the filing date. For more information on the Chapter 11 Cases and related matters, please see Note 1—Business and Organization in Part I, Item 1. Financial Information of this Quarterly Report.
NASDAQ Delisting
Our common stock was traded on the NASDAQ Global Select Market (the “NASDAQ”) under the symbol “XOG” until June 25, 2020. On March 30, 2020, we received a letter from the NASDAQ notifying us that we were not in compliance with the NASDAQ's rules that require the minimum bid price of our stock to be at least $1.00 per share over a consecutive 30-trading-day period. On June 16, 2020, we received a letter from the NASDAQ notifying us that, as a result of the Chapter 11 Cases and in accordance with NASDAQ rules, our securities would be delisted at the opening of business on June 25, 2020. On June 25, 2020, our common stock commenced trading on the Pink Open Market under the symbol “XOGAQ”.
COVID-19 Outbreak and Global Industry Downturn
The recent worldwide outbreak in several countries, including the United States, of a highly transmissible and pathogenic coronavirus (“COVID-19”) and the uncertainty regarding the impact of COVID-19 and various governmental actions taken to mitigate the impact of COVID-19 have resulted in an unprecedented decline in demand for oil and natural gas. At the same time, the decision by Saudi Arabia in March 2020 to drastically reduce export prices and increase oil production followed by curtailment agreements among OPEC and other countries such as Russia further increased uncertainty and volatility around global oil supply-demand dynamics. Decreased demand from much of the United States being on lockdown to prevent the spread of COVID-19 caused domestic storage capacity to begin to fill up during March and April causing further price declines and ultimately causing oil prices to plummet. We expect the excess supply of oil and natural gas in the United States to continue for a sustained period.
The COVID-19 outbreak and its development into a pandemic in March 2020 have required that we take precautionary measures intended to help minimize the risk to our business, employees, customers, suppliers and the communities in which we operate. Our operational employees are currently still able to work on site. However, we have taken various precautionary measures with respect to such operational employees such as requiring them to verify they have not experienced any symptoms consistent with COVID-19, or been in close contact with someone showing such symptoms, before reporting to the work site, quarantining any operational employees who have shown signs of COVID-19 (regardless of whether such employee has been confirmed to be infected) and imposing social distancing requirements on work sites, all in accordance with the guidelines released by the Center for Disease Control. In addition, most of our non-operational employees are now working remotely. We have not yet experienced any material operational disruptions (including disruptions from our suppliers and service providers) as a result of the COVID-19 outbreak, nor have we had any confirmed cases of COVID-19 on any of our work sites.
Due to the decline in crude oil prices and ongoing uncertainty regarding the oil supply-demand macro environment, we have recently reduced our operations in order to preserve capital. Specifically, as part of the Chapter 11 Cases, we have rejected our drilling rig contracts as discussed in Note 14—Commitments and Contingencies in Part I, Item 1. Financial Information of this Quarterly Report.
Please also see Part II, Item 1A in our Annual Report and in this Quarterly Report for further information related to these matters.
Deconsolidation of Elevation Midstream, LLC
Please see Note 1—Business and Organization — Deconsolidation of Elevation Midstream, LLC in Part I, Item 1. Financial Information of this Quarterly Report for information related to the deconsolidation of Elevation Midstream, LLC.
February 2020 Divestiture
In February 2020, we completed the sale of certain non-operated producing properties for aggregate sales proceeds of approximately $12.2 million, subject to customary purchase price adjustments. No gain or loss was recognized for the February 2020 Divestiture. We continue to explore divestitures as part of our ongoing initiative to divest non-strategic assets.
Elevation Common Units
On May 1, 2020, Elevation's board of managers issued 1,530,000,000 common units at a price of $0.01 per unit to certain of Elevation's members other than Extraction through the Capital Raise. The Capital Raise caused our ownership of Elevation to be diluted to less than 0.01%. As a result of the Capital Raise, beginning in May 2020 Extraction began accounting Elevation under the cost method of accounting. We reserve all rights related to actions taken by Elevation’s board of managers.
Midstream Projects
Primarily due to the significant decrease in oil and gas prices during March 2020, Elevation postponed indefinitely further development of gathering systems and facilities that were to be constructed to service our acreage in Hawkeye and another project in the Southwest Wattenberg area.
Senate Bill 19-181 "Protect Public Welfare Oil Andand Gas Operations"
OnIn April 16, 2019, Senate Bill 19-181 (“SB181”("SB181") became law, increasing the regulatory authority of local governments in Colorado over the surface impacts of oil and gas development in anecessary and reasonable manner.manner, and in December 2019, Colorado's Air Quality Control Commission ("AQCC") adopted new rules targeting air emissions from upstream oil and gas operation. Among other things, SB181 (i) repeals a prior law restricting local government land use authority over oil and gas mineral extraction areas to areas designated by the Colorado Oil and Gas Conservation Commission,COGCC, (ii) directs the Colorado Air Quality Control CommissionAQCC to review its leak detection and repair rules and to adopt rules to minimize emissions of certain air pollutants, (iii) clarifies that local governments have authority to regulate the siting of oil and gas locations in a reasonable manner, including the ability to inspect oil and gas facilities, impose fines for leaks, spills, and emissions, and impose fees on operators or owners to cover regulation and enforcement costs, (iv) allows local governments or oil and gas operators to request a technical review board to evaluate the effect of the local government’s preliminary or final determination on the operator’s application, and (v) repeals an exemption for oil and gas production from counties’ authority to regulate noise.noise, (vi) alters forced pooling requirements by increasing the threshold to compel non-consenting individuals into statutory pooling agreements and (vii) elevates the protection of public health, safety, and welfare, the environment, and wildlife resources in the regulation of oil and gas development. Although industry trade associations opposed SB181, management believes that Extraction canhas demonstrated an ability to continue to successfully operate our business. However, the enactment of SB181 and the development and implementation of related rules and regulations, which is under way, could lead to delays and additional costs to our businessbusiness. For example, COGCC rulemaking on flowline safety (completed on November 21, 2019) and the Colorado AQCC and Air Pollution Control Division rulemaking on air quality standards (completed December 20, 2019) – both pursuant to SB181 – could lead to such delays or costs. Certain interest groups in Colorado opposed to oil and natural gas development generally have in previous years advanced various alternatives for ballot initiatives which would result in significantly limiting or preventing oil and natural gas development in the state.
Going Concern.
AuroraPlease see Note 1—Business and Commerce City Operator Agreements
Organization — Ability to Continue as a Going Concern
Extraction entered into operator agreements with the city in Part I, Item 1. Financial Information and “Risk Factors” in Part II, Item 1A of Aurorathis Quarterly Report, as well as “—Liquidity and Commerce City on July 8, 2019 and September 18, 2019, respectively. The agreements established a framework for the permitting process and Extraction’s Best Management Practices while operating within the cities, including electric drilling rigs and quiet hydraulic fracturing fleets. They also identified the wells to be drilled through year-end 2025 and 2024, respectively.
Rocky Mountain Midstream East Greeley Pipeline and Auburn Compressor
On October 14, 2019, Rocky Mountain Midstream commenced service on its East Greeley Pipeline and Auburn Compressor Station. This pipeline and compressor station enables us to flow our oil and gas from parts of our East Greeley area without the bottlenecks or constraints we have historically experienced in this area.
Badger Central Gathering Facility
On October 3, 2019, Elevation commenced moving crude oil, natural gas and water through its Badger central gathering facility, which enables Extraction to efficiently transport its crude oil and natural gas production along with water used during the completion process. The use of this gathering facility allows for the elimination of oil or water storage on the well pad site and reduces truck traffic, which minimizes the impact to the surrounding environment and communities.
Western Gas Outage
During portions of August and September 2019, Extraction’s production on Western Gas' gathering system was significantly curtailed due to an unplanned outage at their Lancaster gas plant. We estimate our third quarter production was negatively impacted by this outage by approximately 8,304 BOE/d. This plant resumed normal operations in October 2019.
November 2019 Credit Facility Amendment
On November 4, 2019, we amended our revolving credit facility to decrease the borrowing base from $1.1 billion to $950.0 million, associated with the scheduled borrowing base redetermination. The current elected commitments were also decreased to $950.0 million.
August 2019 Divestiture
On August 22, 2019, we completed the sale of certain non-operated producing properties for aggregate sales proceeds of approximately $22.0 million, subject to customary purchase price adjustments. No gain or loss was recognized for the August 2019 Divestiture. We continue to explore divestitures, as part of our ongoing initiative to divest of non-strategic assets.
August 2019 Credit Facility Amendment
In August 2019, we amended its revolving credit facility to increase the elected commitments from $900.0 million to $1.0 billion.
Elevation Preferred Units
On July 10, 2019, Elevation closed on an additional 100,000 Elevation Preferred Units under an existing securities purchase agreement with a third party, pursuant to which Elevation had agreed to sell an additional 100,000 Elevation Preferred Units at a price of $990 per Elevation Preferred Unit with an aggregate liquidation preference of $100.0 million, and resulting in net proceeds of approximately $96.5 million, after deducting discounts and related offering expenses. These Elevation Preferred Units are non-recourse to Extraction.
June 2019 Credit Facility Amendment
On June 26, 2019, we amended our revolving credit facility to (i) increase the elected commitments from $650.0 million to $900.0 million, (ii) increase the amount for permitted letters of credit from $50.0 million to $100.0 million and increase the letter of credit sublimit for the Company's oil marketer from $35.0 million to $40.0 million, (iii) decrease the borrowing base from $1.2 billion to $1.1 billion and (iv) increase the limitation on permitted investments from $15.0 million to $20.0 million.
Senior Notes Repurchase Program
On January 4, 2019, our Board of Directors authorized a program, subject to the amendment to our revolving credit facility, to repurchase up to $100.0 million of our Senior Notes (“Senior Notes Repurchase Program”). Our Senior Notes Repurchase Program is subject to restrictions under our Credit Facility and does not obligate us to acquire any specific nominal amount of Senior Notes. During the nine months ended September 30, 2019, we repurchased a nominal value of $49.8 million for $39.3 million in connection with the Senior Notes Repurchase Program.
Stock Repurchase Program
On November 19, 2018, we announced the Board of Directors had authorized a program to repurchase up to $100.0 million of our common stock ("Stock Repurchase Program"). On April 1, 2019, the Company announced the Board of Directors had authorized an extension and increase in our ongoing Stock Repurchase Program bringing the total amount authorized to $163.2 million ("Extended Stock Repurchase Program"). Prior to commencing the Extended Stock Repurchase Program, the Company had purchased approximately 13.0 million shares of its common stock for $63.2 million under the Stock Repurchase Program, which repurchases were completed in the third quarter of 2019, bringing the total amount of common stock repurchased to $163.2 million and completing the Extended Stock Repurchase Program. During the three and nine months ended September 30, 2019, the Company repurchased approximately 4.8 million and 34.1 million shares of its common stock for $21.2 million and $136.9 million, respectively.
How We Evaluate Our Operations
We use a variety of financial and operational metrics to assess the performance of our oil and gas operations, including:
•Sources of revenue;
•Sales volumes;
•Realized prices on the sale of oil, natural gas and NGL, including the effect of our commodity derivative contracts;
•Lease operating expenses (“LOE”);
•Capital expenditures; and
•Adjusted EBITDAX (a Non-GAAP measure).; and
Sources of Revenues
Our revenues are derived from the sale of our oil and natural gas production, as well as the sale of NGLNGLs that are extracted from our natural gas during processing. Our oil, natural gas and NGL revenues do not include the effects of derivatives. For the three months ended SeptemberJune 30, 2020, our revenues were derived 58% from oil sales, 25% from natural gas sales and 17% from NGL sales. For the three months ended June 30, 2019, our revenues were derived 85%83% from oil sales, 10% from natural gas sales and 5%7% from NGL sales. For the threesix months ended SeptemberJune 30, 2018,2020, our revenues were derived 80%71% from oil sales, 8%17% from natural gas sales and 12% from NGL sales. For the ninesix months ended SeptemberJune 30, 2019, our revenues were derived 81%79% from oil sales, 12%13% from natural gas sales and 7% from NGL sales. For the nine months ended September 30, 2018, our revenues were derived 80% from oil sales, 9% from natural gas sales and 11%8% from NGL sales. Our revenues may vary significantly from period to period as a result of changes in volumes of production sold or changes in commodity prices.
Sales Volumes
The following table presents historical sales volumes for the periods indicated:
| | | For the Three Months Ended | | | For the Nine Months Ended | | | For the Three Months Ended | | | For the Six Months Ended | |
| | September 30, | | | September 30, | | | June 30, | | | June 30, | |
| | 2019 | | 2018 | | 2019 | | 2018 | | 2020 | | 2019 | | 2020 | | 2019 |
| Oil (MBbl) | Oil (MBbl) | 3,597 | | | 3,618 | | | 10,830 | | | 10,394 | | Oil (MBbl) | 3,419 | | | 3,650 | | | 6,923 | | | 7,233 | |
| Natural gas (MMcf) | Natural gas (MMcf) | 14,418 | | | 11,838 | | | 43,433 | | | 33,612 | | Natural gas (MMcf) | 17,543 | | | 15,055 | | | 36,546 | | | 29,015 | |
| NGL (MBbl) | NGL (MBbl) | 1,390 | | | 1,372 | | | 4,097 | | | 3,860 | | NGL (MBbl) | 1,979 | | | 1,380 | | | 3,885 | | | 2,707 | |
| Total (MBoe) | Total (MBoe) | 7,390 | | | 6,963 | | | 22,167 | | | 19,855 | | Total (MBoe) | 8,322 | | | 7,540 | | | 16,899 | | | 14,776 | |
| Average net sales (BOE/d) | Average net sales (BOE/d) | 80,327 | | | 75,680 | | | 81,198 | | | 72,731 | | Average net sales (BOE/d) | 91,451 | | | 82,856 | | | 92,852 | | | 81,635 | |
As reservoir pressures decline, production from a given well or formation decreases. Growth or maintenance in our future production and reserves will depend on our ability to continue to add or develop proved reserves in excess of our production. Accordingly, we plan to maintain our focus on adding reserves through organic growth as well as acquisitions. Our ability to add reserves through development projects and acquisitions is dependent on many factors, including takeaway capacity in our areas of operation and our ability to raise capital, obtain regulatory approvals, procure contract drilling rigs and personnel and
successfully identify and consummate acquisitions. Please readrefer to “Risks Related to the Oil, Natural Gas and NGL Industry and Our Business” in Item 1A. of our Annual Report for a further description of the risks that affect us.
Realized Prices on the Sale of Oil, Natural Gas and NGL
Our results of operations depend upon many factors, particularly the price of oil, natural gas and NGL and our ability to market our production effectively. Oil, natural gas and NGL prices are among the most volatile of all commodity prices. For example, during the period from January 1, 2014 to SeptemberJune 30, 2019,2020, NYMEX West Texas Intermediate oil prices ranged from a high of $107.26 per Bbl to a low of $26.21negative $37.63 per Bbl. Average daily prices for NYMEX Henry Hub gas ranged from a high of $6.15 per MMBtu to a low of $1.64$1.48 per MMBtu during the same period. Declines in, and continued depression of, the price of oil and natural gas occurring during 2015, also during 20182019 and 20192020 are due to a combination of factors including increased U.S. supply, global economic concerns stemming from COVID-19 and geopolitical risks.the price war between Russia and Saudi Arabia. These price variations can have a material impact on our financial results and capital expenditures.
Oil pricing is predominatelypredominantly driven by the physical market, supply and demand, financial markets and national and international politics. The NYMEX WTI futures price is a widely used benchmark in the pricing of domestic and imported oil in the United States. The actual prices realized from the sale of oil differ from the quoted NYMEX WTI price as a result of quality and location differentials. In the DJ Basin, oil is sold under various purchase contracts with monthly pricing provisions based on NYMEX pricing, adjusted for differentials.
Natural gas prices vary by region and locality, depending upon the distance to markets, availability of pipeline capacity and supply and demand relationships in that region or locality. The NYMEX Henry Hub price of natural gas is a widely used benchmark for the pricing of natural gas in the United States. Similar to oil, the actual prices realized from the sale of natural gas differ from the quoted NYMEX Henry Hub price as a result of quality and location differentials. For example, wet natural gas with a high Btu content sells at a premium to low Btu content dry natural gas because it yields a greater quantity of NGL. Location differentials to NYMEX Henry Hub prices result from variances in transportation costs based on the natural gas’ proximity to the major consuming markets to which it is ultimately delivered. Also affecting the differential is the processing fee deduction retained by the natural gas processing plant, generally in the form of percentage of proceeds. The price we receive for our natural gas produced in the DJ Basin is based on CIG prices, adjusted for certain deductions.
Our price for NGL produced in the DJ Basin is based on a combination of prices from the Conway hub in Kansas and Mont Belvieu in Texas where this production is marketed.
The following table provides the high and low prices for NYMEX WTI and NYMEX Henry Hub prompt month contract prices and our differential to the average of those benchmark prices for the periods indicated. The differential varies, but our oil, natural gas and NGL normally sells at a discount to the NYMEX WTI and NYMEX Henry Hub price, as applicable.
| | | For the Three Months Ended | | | For the Nine Months Ended | | | For the Three Months Ended | | | For the Six Months Ended | |
| | September 30, | | | September 30, | | | June 30, | | | June 30, | |
| | 2019 | | 2018 | | 2019 | | 2018 | | 2020 | | 2019 | | 2020 | | 2019 |
| Oil | Oil | As restated | | | | As restated | | | Oil | | | | | | | |
| NYMEX WTI High ($/Bbl) | NYMEX WTI High ($/Bbl) | $ | 62.90 | | | $ | 74.14 | | | $ | 66.30 | | | $ | 74.15 | | NYMEX WTI High ($/Bbl) | $ | 40.46 | | | $ | 66.30 | | | $ | 63.27 | | | $ | 66.30 | |
| NYMEX WTI Low ($/Bbl) | NYMEX WTI Low ($/Bbl) | $ | 51.09 | | | $ | 65.01 | | | $ | 46.54 | | | $ | 59.19 | | NYMEX WTI Low ($/Bbl) | $ | (37.63) | | | $ | 51.14 | | | $ | (37.63) | | | $ | 46.54 | |
| NYMEX WTI Average ($/Bbl) | NYMEX WTI Average ($/Bbl) | $ | 56.44 | | | $ | 69.43 | | | $ | 57.10 | | | $ | 66.79 | | NYMEX WTI Average ($/Bbl) | $ | 28.00 | | | $ | 59.91 | | | $ | 36.82 | | | $ | 57.45 | |
| Average Realized Price ($/Bbl) | $ | 41.99 | | | $ | 62.32 | | | $ | 46.31 | | | $ | 59.58 | | |
Average Realized Price ($/Bbl)(1) | | Average Realized Price ($/Bbl)(1) | $ | 10.61 | | | $ | 50.72 | | | $ | 23.18 | | | $ | 48.46 | |
Average Realized Price, with derivative settlements ($/Bbl) | Average Realized Price, with derivative settlements ($/Bbl) | $ | 45.58 | | | $ | 50.02 | | | $ | 43.77 | | | $ | 48.23 | | Average Realized Price, with derivative settlements ($/Bbl) | $ | 18.11 | | | $ | 43.83 | | | $ | 31.97 | | | $ | 42.87 | |
| Average Realized Price as a % of Average NYMEX WTI | Average Realized Price as a % of Average NYMEX WTI | 74.4 | % | | 89.8 | % | | 81.1 | % | | 89.2 | % | Average Realized Price as a % of Average NYMEX WTI | 37.9 | % | | 84.7 | % | | 63.0 | % | | 84.4 | % |
Differential ($/Bbl) to Average NYMEX WTI (1)(2) | Differential ($/Bbl) to Average NYMEX WTI (1)(2) | $ | (8.28) | | | $ | (7.11) | | | $ | (8.74) | | | $ | (7.21) | | Differential ($/Bbl) to Average NYMEX WTI (1)(2) | $ | (16.26) | | | $ | (9.19) | | | $ | (11.85) | | | $ | (8.99) | |
| Natural Gas | Natural Gas | | Natural Gas | | |
| NYMEX Henry Hub High ($/MMBtu) | NYMEX Henry Hub High ($/MMBtu) | $ | 2.68 | | | $ | 3.08 | | | $ | 3.59 | | | $ | 3.63 | | NYMEX Henry Hub High ($/MMBtu) | $ | 2.13 | | | $ | 2.71 | | | $ | 2.20 | | | $ | 3.59 | |
| NYMEX Henry Hub Low ($/MMBtu) | NYMEX Henry Hub Low ($/MMBtu) | $ | 2.07 | | | $ | 2.72 | | | $ | 2.07 | | | $ | 2.55 | | NYMEX Henry Hub Low ($/MMBtu) | $ | 1.48 | | | $ | 2.19 | | | $ | 1.48 | | | $ | 2.19 | |
| NYMEX Henry Hub Average ($/MMBtu) | NYMEX Henry Hub Average ($/MMBtu) | $ | 2.33 | | | $ | 2.86 | | | $ | 2.56 | | | $ | 2.85 | | NYMEX Henry Hub Average ($/MMBtu) | $ | 1.75 | | | $ | 2.51 | | | $ | 1.81 | | | $ | 2.69 | |
| NYMEX Henry Hub Average converted to a $/Mcf basis (factor of 1.1 to 1) | $ | 2.56 | | | $ | 3.15 | | | $ | 2.82 | | | $ | 3.14 | | |
NYMEX Henry Hub Average converted to a $/Mcf basis(3) | | NYMEX Henry Hub Average converted to a $/Mcf basis(3) | $ | 1.93 | | | $ | 2.76 | | | $ | 1.99 | | | $ | 2.96 | |
| Average Realized Price ($/Mcf) | Average Realized Price ($/Mcf) | $ | 1.17 | | | $ | 1.95 | | | $ | 1.71 | | | $ | 1.99 | | Average Realized Price ($/Mcf) | $ | 0.91 | | | $ | 1.44 | | | $ | 1.05 | | | $ | 1.98 | |
| Average Realized Price, with derivative settlements ($/Mcf) | Average Realized Price, with derivative settlements ($/Mcf) | $ | 1.33 | | | $ | 2.08 | | | $ | 1.69 | | | $ | 2.37 | | Average Realized Price, with derivative settlements ($/Mcf) | $ | 1.24 | | | $ | 1.53 | | | $ | 1.32 | | | $ | 1.88 | |
Average Realized Price as a % of Average NYMEX Henry Hub | Average Realized Price as a % of Average NYMEX Henry Hub | 45.7 | % | | 61.9 | % | | 60.6 | % | | 63.4 | % | Average Realized Price as a % of Average NYMEX Henry Hub | 47.2 | % | | 52.2 | % | | 52.8 | % | | 66.9 | % |
Differential ($/Mcf) to Average NYMEX Henry Hub | Differential ($/Mcf) to Average NYMEX Henry Hub | $ | (1.39) | | | $ | (1.20) | | | $ | (1.11) | | | $ | (1.15) | | Differential ($/Mcf) to Average NYMEX Henry Hub | $ | (1.02) | | | $ | (1.32) | | | $ | (0.94) | | | $ | (0.98) | |
| NGL | NGL | | NGL | | |
| Average Realized Price ($/Bbl) | $ | 6.55 | | | $ | 24.49 | | | $ | 10.97 | | | $ | 22.38 | | |
Average Realized Price ($/Bbl)(4) | | Average Realized Price ($/Bbl)(4) | $ | 5.47 | | | $ | 11.04 | | | $ | 7.21 | | | $ | 13.24 | |
| Average Realized Price as a % of Average NYMEX WTI | Average Realized Price as a % of Average NYMEX WTI | 11.6 | % | | 35.3 | % | | 19.2 | % | | 33.5 | % | Average Realized Price as a % of Average NYMEX WTI | 19.5 | % | | 18.4 | % | | 19.6 | % | | 23.0 | % |
| BOE | BOE | | BOE | | |
Average Realized Price per BOE | Average Realized Price per BOE | $ | 23.94 | | | $ | 40.53 | | | $ | 28.01 | | | $ | 38.91 | | Average Realized Price per BOE | $ | 7.59 | | | $ | 29.45 | | | $ | 13.42 | | | $ | 30.05 | |
| Average Realized Price per BOE with derivative settlements | Average Realized Price per BOE with derivative settlements | $ | 26.01 | | | $ | 34.35 | | | $ | 26.73 | | | $ | 33.62 | | Average Realized Price per BOE with derivative settlements | $ | 11.35 | | | $ | 26.30 | | | $ | 17.60 | | | $ | 27.09 | |
(1) ExcludesIncludes non-cash amounts allocated to a satisfied performance obligation, recognized within oil sales for the three and ninesix months ended SeptemberJune 30, 2019,2020, pursuant to ASC 606, Revenue Recognition.
(2)Excludes non-cash amounts allocated to a satisfied performance obligation, recognized within oil sales for the three and six months ended June 30, 2020, pursuant to ASC 606, Revenue Recognition.
43(3)Based on the difference between our average realized price and the NYMEX Henry Hub Average as converted into Mcf using a conversion factor of 1.1 to 1.
Table of Contents(4)The decrease year over year is primarily due to capacity constraints in transporting the wet gas associated with our production coupled with negative market conditions surrounding limited export capacity.
Derivative Arrangements
To achieve more predictable cash flow and to reduce our exposure to adverse fluctuations in commodity prices, from time to time, we enter into derivative arrangements for our oil and natural gas production. By removing a significant portion of price volatility associated with our oil and natural gas production, we believe we will mitigate, but not eliminate, the potential negative effects of reductions in oil and natural gas prices on our cash flow from operations for those periods. However, in a portion of our current positions, our hedging activity may also reduce our ability to benefit from increases in oil and natural gas prices. We will sustain losses to the extent our derivatives contract prices are lower than market prices and, conversely, we will realize gains to the extent our derivatives contract prices are higher than market prices. In certain circumstances where we have unrealized gains in our derivative portfolio, we may choose to restructure existing derivative contracts or enter into new transactions to modify the terms of current contracts in order to realize the current value of our existing positions.contracts. See “—Quantitative and Qualitative Disclosure About Market Risk—Commodity Price Risk” for information regarding our exposure to market risk, including the effects of changes in commodity prices, and our commodity derivative contracts.
We will continue to use commodity derivative instruments to hedge our price risk in the future. Our hedging strategy and future hedging transactions will be determined at our discretion and may be different than what we have done on a historical basis. As a result of recent volatility in the price of oil and natural gas, weWe have relied on a variety of hedging strategies and instruments to hedge our future price risk. We have utilized swaps, put options and call options, which in some instances require the payment of a premium, to reduce the effect of price changes on a portion of our future oil and natural gas production. We expect to continue to use a variety of hedging strategies and instruments for the foreseeable future.
A swap has an established fixed price. WhenThe hedge prices will depend on the settlementcommodity price is below the fixed price, the counterparty pays us an amount equal to the difference between the settlement price and the fixed price multiplied by the hedged contract volume. When the settlement price is above the fixed price, we pay our counterparty an amount equal to the difference between the settlement price and the fixed price multiplied by the hedged contract volume.
A put option has an established floor price. The buyer of the put option pays the seller a premium to enter into the put option. When the settlement price is below the floor price, the seller pays the buyer an amount equal to the difference between the settlement price and the strike price multiplied by the hedged contract volume. When the settlement price is above the floor price, the put option expires worthless. Some of our purchased put options have deferred premiums. For the deferred premium puts, we agreed to pay a premium to the counterpartyenvironment at the time of settlement.
A call option has an established ceiling price. The buyer of the call option pays the seller a premium to enter into the call option. When the settlement price is above the ceiling price, the seller pays the buyer an amount equal to the difference between the settlement price and the strike price multiplied by the hedged contract volume. When the settlement price is below the ceiling price, the call option expires worthless.
We combine swaps, purchased put options, sold put options and sold call options in order to achieve various hedging strategies. Some examples of our hedging strategiesthose hedge transactions are collars which include purchased put options and sold call options, three-way collars which include purchased put options, sold put options and sold call options, and enhanced swaps, which include either sold put options or sold call options with the associated premiums rolled into an enhanced fixed price swap. We have historically relied on commodity derivative contracts to mitigate our exposure to lower commodity prices.
We have historically been able to hedge our oil and natural gas production at prices that are significantly higher than current strip prices. However, inentered into. In the current commodity price environment, our ability to enter into comparable derivative arrangements at favorable prices may be limited, and, we are not obligated to hedge a specific portion of our oil or natural gas production.
For a description of our derivative instruments that we utilize and a summary of the Company’sour commodity derivative contracts as of SeptemberJune 30, 2019,2020, please see Note 5—7—Commodity Derivative Instruments in Part 1,I, Item 11. Financial Information of this Quarterly Report.
The following table summarizes our historical derivative positions and the settlement amounts for each of the periods indicated.
| | | | | | | | | | | |
| For the Nine Months Ended | | |
| September 30, | | |
| 2019 | | 2018 |
| NYMEX WTI Crude Swaps: | | | |
| Notional volume (Bbl) | 5,580,000 | | | 4,000,000 | |
| Weighted average fixed price ($/Bbl) | $ | 52.55 | | | $ | 51.23 | |
| NYMEX WTI Crude Purchased Puts: | | | |
| Notional volume (Bbl) | 15,800,000 | | | 10,077,600 | |
| Weighted average purchased put price ($/Bbl) | $ | 46.59 | | | $ | 43.70 | |
| NYMEX WTI Crude Purchased Calls: | | | |
| Notional volume (Bbl) | 14,000,000 | | | 1,740,000 | |
| Weighted average purchased call price ($/Bbl) | $ | 64.99 | | | $ | 58.90 | |
| NYMEX WTI Crude Sold Calls: | | | |
| Notional volume (Bbl) | 17,750,000 | | | 6,730,000 | |
| Weighted average sold call price ($/Bbl) | $ | 63.69 | | | $ | 57.14 | |
| NYMEX WTI Crude Sold Puts: | | | |
| Notional volume (Bbl) | 15,300,000 | | | 10,088,800 | |
| Weighted average sold put price ($/Bbl) | $ | 44.33 | | | $ | 38.80 | |
| NYMEX HH Natural Gas Swaps: | | | |
| Notional volume (MMBtu) | 23,400,000 | | | 30,750,000 | |
| Weighted average fixed price ($/MMBtu) | $ | 2.83 | | | $ | 3.12 | |
| NYMEX HH Natural Gas Purchased Puts: | | | |
| Notional volume (MMBtu) | 3,600,000 | | | 1,800,000 | |
| Weighted average purchased put price ($/MMBtu) | $ | 3.04 | | | $ | 3.00 | |
| NYMEX HH Natural Gas Sold Calls: | | | |
| Notional volume (MMBtu) | 3,600,000 | | | 1,800,000 | |
| Weighted average sold call price ($/MMBtu) | $ | 3.46 | | | $ | 3.15 | |
| NYMEX HH Natural Gas Sold Puts: | | | |
| Notional volume (MMBtu) | 3,000,000 | | | — | |
| Weighted average sold put price ($/MMBtu) | $ | 2.50 | | | $ | — | |
| CIG Basis Gas Swaps: | | | |
| Notional volume (MMBtu) | 31,100,000 | | | 26,895,000 | |
| Weighted average fixed basis price ($/MMBtu) | $ | (0.73) | | | $ | (0.59) | |
| Total Amounts Received/(Paid) from Settlement (in thousands) | $ | (8,432) | | | $ | (99,914) | |
| Cash provided by changes in Accounts Receivable and Accounts Payable related to Commodity Derivatives | $ | (10,095) | | | $ | 6,432 | |
| Cash Settlements on Commodity Derivatives per Consolidated Statements of Cash Flows | $ | (18,527) | | | $ | (93,482) | |
| | | | | | | | | | | |
| For the Six Months Ended | | |
| June 30, | | |
| 2020 | | 2019 |
| NYMEX WTI Crude Swaps: | | | |
| Notional volume (Bbl) | 525,000 | | | 3,000,000 | |
| Weighted average fixed price ($/Bbl) | $ | 60.05 | | | $ | 54.64 | |
| NYMEX WTI Crude Purchased Puts: | | | |
| Notional volume (Bbl) | 4,950,000 | | | 9,850,000 | |
| Weighted average purchased put price ($/Bbl) | $ | 54.48 | | | $ | 46.21 | |
| NYMEX WTI Crude Purchased Calls: | | | |
| Notional volume (Bbl) | 1,100,000 | | | 10,500,000 | |
| Weighted average purchased call price ($/Bbl) | $ | 68.04 | | | $ | 63.59 | |
| NYMEX WTI Crude Sold Calls: | | | |
| Notional volume (Bbl) | 5,650,000 | | | 13,400,000 | |
| Weighted average sold call price ($/Bbl) | $ | 63.37 | | | $ | 62.24 | |
| NYMEX WTI Crude Sold Puts: | | | |
| Notional volume (Bbl) | 5,300,000 | | | 8,700,000 | |
| Weighted average sold put price ($/Bbl) | $ | 44.39 | | | $ | 43.58 | |
| NYMEX HH Natural Gas Swaps: | | | |
| Notional volume (MMBtu) | 17,400,000 | | | 14,400,000 | |
| Weighted average fixed price ($/MMBtu) | $ | 2.75 | | | $ | 2.88 | |
| NYMEX HH Natural Gas Purchased Puts: | | | |
| Notional volume (MMBtu) | 600,000 | | | 3,600,000 | |
| Weighted average purchased put price ($/MMBtu) | $ | 2.90 | | | $ | 3.04 | |
| NYMEX HH Natural Gas Sold Calls: | | | |
| Notional volume (MMBtu) | 600,000 | | | 3,600,000 | |
| Weighted average sold call price ($/MMBtu) | $ | 3.48 | | | $ | 3.46 | |
| NYMEX HH Natural Gas Sold Puts: | | | |
| Notional volume (MMBtu) | — | | | 3,000,000 | |
| Weighted average sold put price ($/MMBtu) | $ | — | | | $ | 2.50 | |
| CIG Basis Gas Swaps: | | | |
| Notional volume (MMBtu) | 22,800,000 | | | 20,000,000 | |
| Weighted average fixed basis price ($/MMBtu) | $ | (0.61) | | | $ | (0.74) | |
| Total Amounts Received/(Paid) from Settlement (in thousands) | $ | 166,725 | | | $ | (24,532) | |
| Cash provided by changes in Accounts Receivable and Accounts Payable related to Commodity Derivatives | $ | (5,213) | | | $ | 2,614 | |
| Derivative unwinds reducing the Credit Facility balance | $ | (96,065) | | | $ | — | |
| Settlements on Commodity Derivatives per Condensed Consolidated Statements of Cash Flows | $ | 65,447 | | | $ | (21,918) | |
Lease Operating Expenses
All direct and allocated indirect costs of lifting hydrocarbons from a producing formation to the surface constitutes part of the current operating expenses of a working interest. Such costs include labor, superintendence, supplies, repairs, maintenance, water injection and disposal costs, allocated overhead charges, workover, insurance and other expenses incidental to production, but exclude lease acquisition or drilling or completion expenses.
Capital Expenditures
For the ninesix months ended SeptemberJune 30, 2019,2020, we incurred approximately $472.0$158.6 million in drilling and completion capital expenditures, excluding the impact of a decrease in outstanding elections of $7.9 million.expenditures. For the ninesix months ended SeptemberJune 30, 2019,2020, we drilled 9137.0 gross (74.6(26.5 net) wells with an average lateral length of approximately 9,100 feet2.3 miles and completed 11341.0 gross (98.2(31.6 net) wells with an average lateral length of approximately 8,700 feet.2.4 miles. We turned to sales 6531 gross (56.7(24.4 net) wells with an average lateral length of approximately 8,000 feet.2.3 miles. In addition, we incurred approximately $44.5$11.1 million of leasehold and surface acreage additions, excluding the impact of the increase in outstanding elections of $3.0 million. In addition, Elevation Midstream, LLC, our wholly owned midstream subsidiary, incurred $192.6 million of capital expenditures during the nine months ended September 30, 2019. These capital expenditures are funded entirely pursuant to the Elevation Midstream, LLC Securities Purchase Agreement.
In October 2019, we revised our 2019 capital budget for the drilling and completion of operated and non-operated wells from a range of $585.0 million to $675.0 million to approximately $520.0 million to $550.0 million. We intend to allocate substantially all our capital budget to the Core DJ Basin. We expected to drill 125 gross operated wells, complete 122 gross operated wells and turn-in-line 111 gross operated wells. As a result of the change in our capital budget, we expect to drill 108 gross operated wells, complete 118 gross operated wells and turn-in-line 113 gross operated wells. Our capital budget still anticipates a one to two operated rig drilling program and excludes up to $250.0 million for Elevation, which is fully funded by a third party and any amounts that may be paid for potential acquisitions.
The amount and timing of these capital expenditures is within our control and subject to our management’s discretion. We retain the flexibility to defer a portion of these planned capital expenditures depending on a variety of factors, including but not limited to the success of our drilling activities, prevailing and anticipated prices for oil, natural gas and NGL, the availability of necessary equipment, infrastructure and capital, the receipt and timing of required regulatory permits and approvals, seasonal conditions, drilling and acquisition costs and the level of participation by other interest owners. Any postponement or elimination of our development drilling program could result in a reduction of proved reserve volumes and related standardized measure. These risks could materially affect our business, financial condition and results of operations.additions.
Adjusted EBITDAX
Adjusted EBITDAX is not a measure of net income (loss) as determined by United States generally accepted accounting principles (“GAAP”).GAAP. Adjusted EBITDAX is a supplemental non-GAAP financial measure that is used by management and external users of our financial statements, such as industry analysts, investors, lenders and rating agencies. We define Adjusted EBITDAX as net income (loss) adjusted for certain cash and non-cash items, including depletion, depreciation, amortization and accretion (“DD&A”)(DD&A), impairment of long lived assets, non-recurring charges in other operating expenses, exploration and abandonment expenses, gain on sale of property and equipment, and assets of unconsolidated subsidiary, (gain) loss on commodity derivatives, settlements on commodity derivative instruments, premiums paid for derivatives that settled during the period, stock-based compensation expense, amortization of debt issuance costs, make-whole premiums, gain on repurchase of senior notes, interest expense, income tax expense (benefit), loss on deconsolidation of Elevation Midstream, LLC and non-recurring charges.reorganization items, net. Adjusted EBITDAX is also used to evaluate the performance of reportable segments. SeePlease see Note 13 - 16—Segment Information in Part I, Item 8 in1. Financial Information of this Quarterly Report for more information regarding the EBITDAX of reportable segments.
Management believes Adjusted EBITDAX is useful because it allows us to more effectively evaluate our operating performance and compare the results of our operations from period to period without regard to our financing methods or capital structure. We exclude the items listed above from net income (loss) in arriving at Adjusted EBITDAX because these amounts can vary substantially from company to company within our industry depending upon accounting methods and book values of assets, capital structures and the method by which the assets were acquired. Adjusted EBITDAX should not be considered as an alternative to, or more meaningful than, net income (loss) as determined in accordance with GAAP or as an indicator of our operating performance. Certain items excluded from Adjusted EBITDAX are significant components in understanding and assessing a company's financial performance, such as a company's cost of capital, hedging strategy and tax structure, as well as the historic costs of depreciable assets, none of which are components of Adjusted EBITDAX. Our computations of Adjusted EBITDAX may not be comparable to other similarly titled measure of other companies. We believe that Adjusted EBITDAX is
a widely followed measure of operating performance. Additionally, our management team believes Adjusted EBITDAX is useful to an investor in evaluating our financial performance because this measure (i) is widely used by investors in the oil and natural gas industry to measure a company’s operating performance without regard to items excluded from the calculation of such term, among other factors; (ii) helps investors to more meaningfully evaluate and compare the results of our operations from period to period by removing the effect of our capital structure from our operating structure; and (iii) is used by our management team for various purposes, including as a measure of operating performance, in presentations to our board of directors, as a basis for strategic planning and forecasting.
The following table presents a reconciliation of Adjusted EBITDAX to the GAAP financial measure of net income (loss) for each of the periods indicated (in thousands).
| | | | | | | | | | | | | | | | | | | | | | | |
| For the Three Months Ended
September 30, | | | | For the Nine Months Ended
September 30, | | |
| 2019 | | 2018 | | 2019 | | 2018 |
| As restated | | | | As restated | | |
| Reconciliation of Net Income (Loss) to Adjusted EBITDAX: | | | | | | | |
| Net income (loss) | $ | 33,924 | | | $ | 65,150 | | | $ | (16,664) | | | $ | 22,003 | |
| Add back: | | | | | | | |
| Depletion, depreciation, amortization and accretion | 114,996 | | | 107,315 | | | 352,134 | | | 310,296 | |
| Impairment of long lived assets | — | | | 16,166 | | | 11,233 | | | 16,294 | |
| Exploration expenses | 13,245 | | | 11,038 | | | 32,725 | | | 21,326 | |
| Gain on sale of property and equipment and assets of unconsolidated subsidiary | (1,011) | | | (83,559) | | | (1,329) | | | (143,461) | |
| (Gain) loss on commodity derivatives | (87,956) | | | 35,913 | | | (39,383) | | | 175,752 | |
| Settlements on commodity derivative instruments | 16,101 | | | (41,009) | | | (8,432) | | | (99,914) | |
| Premiums paid for derivatives that settled during the period | (812) | | | (1,956) | | | (19,910) | | | (5,191) | |
| Stock-based compensation expense | 11,358 | | | 17,420 | | | 39,306 | | | 50,883 | |
| Amortization of debt issuance costs | 974 | | | 935 | | | 3,799 | | | 12,303 | |
| Make-whole premium on 2021 Senior Notes | — | | | — | | | — | | | 35,600 | |
| Gain on repurchase of 2026 Senior Notes | — | | | — | | | (10,486) | | | — | |
| Interest expense | 22,250 | | | 19,790 | | | 61,478 | | | 55,326 | |
| Income tax expense | 14,800 | | | 22,200 | | | 900 | | | 12,300 | |
| Adjusted EBITDAX | $ | 137,869 | | | $ | 169,403 | | | $ | 405,371 | | | $ | 463,517 | |
| | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | |
| For the Three Months Ended June 30, | | | | For the Six Months Ended June 30, | | |
| 2020 | | 2019 | | 2020 | | 2019 |
| Reconciliation of Net Income (Loss) to Adjusted EBITDAX: | | | | | | | |
| Net income (loss) | $ | (291,934) | | | $ | 43,444 | | | $ | (282,897) | | | $ | (50,588) | |
| Add back: | | | | | | | |
| Depletion, depreciation, amortization and accretion | 82,620 | | | 118,368 | | | 158,670 | | | 237,138 | |
| Impairment of long lived assets | 960 | | | 2,985 | | | 1,736 | | | 11,233 | |
| Other operating expenses | 13,209 | | | — | | | 65,784 | | | — | |
| Exploration and abandonment expenses | 62,661 | | | 13,287 | | | 175,141 | | | 19,481 | |
| Gain on sale of property and equipment | — | | | (97) | | | — | | | (319) | |
| (Gain) loss on commodity derivatives | 69,301 | | | (73,519) | | | (193,714) | | | 48,572 | |
| Settlements on commodity derivative instruments | 127,429 | | | (14,203) | | | 166,725 | | | (24,532) | |
| Premiums paid for derivatives that settled during the period | — | | | (9,549) | | | — | | | (19,098) | |
| Stock-based compensation expense | 2,560 | | | 14,937 | | | 2,560 | | | 27,945 | |
| Amortization of debt issuance costs | 1,948 | | | 1,328 | | | 3,190 | | | 2,826 | |
| Gain on repurchase of 2026 Senior Notes | — | | | (3,169) | | | — | | | (10,486) | |
| Interest expense | 18,366 | | | 20,399 | | | 38,482 | | | 39,226 | |
| Income tax expense (benefit) | — | | | 15,100 | | | 2,200 | | | (13,900) | |
| Loss on deconsolidation of Elevation Midstream, LLC | — | | | — | | | 73,139 | | | — | |
| Reorganization items, net | 26,919 | | — | | 26,919 | | — |
| Adjusted EBITDAX | $ | 114,039 | | | $ | 129,311 | | | $ | 237,935 | | | $ | 267,498 | |
Free Cash Flow
Our Free Cash Flow is not a measure of net income (loss) as determined by GAAP. We define Free Cash Flow as Discretionary Cash Flow (non-GAAP) less Adjusted Cash Flow used in Investing (non-GAAP) adjusted for Other Non-Recurring Adjustments (non-GAAP). Discretionary Cash Flow is defined as net cash provided by operating activities (GAAP) less changes in working capital (current assets and liabilities). Adjusted Cash Flow used in Investing is defined as cash flow used in investing activities (GAAP) adjusted for changes in accounts payable and accrued liabilities related to capital expenditures.
Free Cash Flow is used by management and external users of our financial statements, such as industry analysts, investors, lenders and rating agencies. We believe Free Cash Flow can provide additional transparency into the drivers of trends in our operating cash flows, such as production, realized sales prices and operating costs, as it disregards the timing of settlement of operating assets and liabilities. We believe Free Cash Flow provides additional information that may be useful in an analysis of our ability to generate cash to fund exploration and development activities, construct and support midstream assets, and to return capital to stockholders.
The following tables present a reconciliation of Discretionary Cash Flow and Free Cash Flow to the GAAP financial measure of net cash provided by operating activities for each of the periods indicated.
| | | | | | | | | | | | | | | | | |
| Upstream | | Midstream | | Consolidated |
| For the Three Months Ended June 30, 2020 | | | | |
| Cash Flow from Operating Activities | | | | | |
| Net cash used in operating activities | $ | (63,145) | | | $ | — | | | $ | (63,145) | |
| Changes in current assets and liabilities | 52,983 | | | — | | | 52,983 | |
| Discretionary Cash Flow | (10,162) | | | — | | | (10,162) | |
| | | | | |
| Cash Flow from Investing Activities | | | | | |
| Net cash used in investing activities | (51,710) | | | — | | | (51,710) | |
| Change in accounts payable and accrued liabilities related to capital expenditures | 34,851 | | | — | | | 34,851 | |
| Adjusted Cash Flow used in Investing | (16,859) | | | — | | | (16,859) | |
| | | | | |
Other Non-Recurring Adjustments(1) | — | | | — | | | — | |
| | | | | |
| Free Cash Flow | $ | (27,021) | | | $ | — | | | $ | (27,021) | |
| | | | | | | | | | | | | | | | | |
| Upstream | | Midstream | | Consolidated |
| For the Three Months Ended June 30, 2019 | | | | |
| Cash Flow from Operating Activities | | | | | |
| Net cash provided by (used in) operating activities | $ | 85,701 | | | $ | (1,368) | | | $ | 84,333 | |
| Changes in current assets and liabilities | 27,807 | | | (322) | | | 27,485 | |
| Discretionary Cash Flow | 113,508 | | | (1,690) | | | 111,818 | |
| | | | | |
| Cash Flow from Investing Activities | | | | | |
| Net cash used in investing activities | (140,435) | | | (76,434) | | | (216,869) | |
| Change in accounts payable and accrued liabilities related to capital expenditures | (78,059) | | | (2,300) | | | (80,359) | |
| Adjusted Cash Flow used in Investing | (218,494) | | | (78,734) | | | (297,228) | |
| | | | | |
Other Non-Recurring Adjustments(1) | 3,728 | | | — | | | 3,728 | |
| | | | | |
| Free Cash Flow | $ | (101,258) | | | $ | (80,424) | | | $ | (181,682) | |
| | | | | | | | | | | | | | | | | |
| Upstream | | Midstream | | Consolidated |
| For the Six Months Ended June 30, 2020 | | | | |
| Cash Flow from Operating Activities | | | | | |
| Net cash provided by operating activities | $ | 81,074 | | | $ | 2,880 | | | $ | 83,954 | |
| Changes in current assets and liabilities | (48,064) | | | (1,907) | | | (49,971) | |
| Discretionary Cash Flow | 33,010 | | | 973 | | | 33,983 | |
| | | | | |
| Cash Flow from Investing Activities | | | | | |
| Net cash used in investing activities | (185,573) | | | (5,840) | | | (191,413) | |
| Change in accounts payable and accrued liabilities related to capital expenditures | 24,374 | | | 2,210 | | | 26,584 | |
| Adjusted Cash Flow used in Investing | (161,199) | | | (3,630) | | | (164,829) | |
| | | | | |
Other Non-Recurring Adjustments(1) | 1,170 | | | — | | | 1,170 | |
| | | | | |
| Free Cash Flow | $ | (127,019) | | | $ | (2,657) | | | $ | (129,676) | |
| | | | | | | | | | | | | | | | | |
| Upstream | | Midstream | | Consolidated |
| For the Six Months Ended June 30, 2019 | | | | |
| Cash Flow from Operating Activities | | | | | |
| Net cash provided by operating activities | $ | 216,822 | | | $ | 1,622 | | | $ | 218,444 | |
| Changes in current assets and liabilities | 31,441 | | | (769) | | | 30,672 | |
| Discretionary Cash Flow | 248,263 | | | 853 | | | 249,116 | |
| | | | | |
| Cash Flow from Investing Activities | | | | | |
| Net cash used in investing activities | (325,154) | | | (124,090) | | | (449,244) | |
| Change in accounts payable and accrued liabilities related to capital expenditures | (69,709) | | | (11,866) | | | (81,575) | |
| Adjusted Cash Flow used in Investing | (394,863) | | | (135,956) | | | (530,819) | |
| | | | | |
Other Non-Recurring Adjustments(1) | 5,310 | | | — | | | 5,310 | |
| | | | | |
| Free Cash Flow | $ | (141,290) | | | $ | (135,103) | | | $ | (276,393) | |
(1) Amount incurred for the construction of our field office that is included in other property and equipment in our condensed consolidated statements of cash flows.
Items Affecting the Comparability of Our Financial Results
Our historical results of operations for the periods presented may not be comparable, either to each other or to our future results of operations, for the reasons described below:
•On January 1,During the Chapter 11 Cases, we expect our financial results to continue to be volatile as restructuring activities and expenses, contract terminations and rejections and claims assessments significantly impact our financial results. For the three and six months ended June 30, 2020, we incurred $26.9 million of reorganization items, net as compared to none in 2019. As a result, our historical financial performance is likely not indicative of financial performance after the date of the bankruptcy filing.
•For the six months ended June 30, 2020 and 2019, we adopted ASC 842 - respectively, exploration and abandonment expenses increased primarily due to the abandonment of $169.6 million and $15.0 million of unproved properties.
•Leases.Elevation Midstream, LLC was deconsolidated as of March 16, 2020 and accounted for as an equity method investment. We adopted usingelected the modified retrospective transition approachfair value option to applyremeasure the new standard to all leases entered intoElevation Midstream, LLC equity method investment and determined it had no fair value. We recorded a $73.1 million loss on or after January 1, 2019 and all existing leases. ASC 842 supersedes previous lease recognition requirements in ASC 840 and resulteddeconsolidation of Elevation Midstream, LLC in the recognitioncondensed consolidated statements of $20.5operations for the six months ended June 30, 2020. Please see Note 1—Business and Organization — Deconsolidation of Elevation Midstream, LLC in Part I, Item 1. Financial Information of this Quarterly Report for information related to the deconsolidation of Elevation Midstream, LLC.
•On April 2, 2020, Elevation demanded payment of $46.8 million of right-of-use assets and $26.1 million of lease liabilitiesdue to an alleged breach in contract stemming from a purported failure to complete the pipeline extensions connecting certain wells to the Badger central gathering facility prior to April 1, 2020. While we dispute that these amounts are due to Elevation, under ASC Topic 450 - Contingencies, we recorded the amount in other operating expenses on the condensed consolidated balance sheet asstatements of Septemberoperations for the six months ended June 30, 2019. See "Part I, Item 1, Note 2—Basis of Presentation, Restatement, Significant Accounting Policies and Recent Accounting Pronouncements—Leases" for additional information.2020.
Historical Results of Operations and Operating Expenses
Oil, Natural Gas and NGL Sales Revenues, Operating Expenses and Other Income (Expense).
The following table provides theFor components of our revenues, operating expenses, other income (expense) and net income (loss) for the periods indicated (in thousands):
| | | | | | | | | | | | | | | | | | | | | | | |
| For the Three Months Ended | | | | For the Nine Months Ended | | |
| September 30, | | | | September 30, | | |
| 2019 | | 2018 | | 2019 | | 2018 |
| (Unaudited) | | | | | | |
| As restated | | | | As restated | | |
| Revenues: | | | | | | | |
| Oil sales | $ | 151,042 | | | $ | 225,467 | | | $ | 501,591 | | | $ | 619,211 | |
| Natural gas sales | 16,801 | | | 23,103 | | | 74,385 | | | 66,991 | |
| NGL sales | 9,099 | | | 33,590 | | | 44,940 | | | 86,369 | |
| Total Revenues | 176,942 | | | 282,160 | | | 620,916 | | | 772,571 | |
| Operating Expenses: | | | | | | | |
| Lease operating expenses | 22,979 | | | 20,283 | | | 68,445 | | | 61,760 |
| Transportation and gathering | 6,922 | | | 11,786 | | | 29,142 | | | 29,284 | |
| Production taxes | 9,711 | | | 21,605 | | | 46,419 | | | 66,317 | |
| Exploration expenses | 13,245 | | | 11,038 | | | 32,725 | | | 21,326 | |
| Depletion, depreciation, amortization and accretion | 114,996 | | | 107,315 | | | 352,134 | | | 310,296 | |
| Impairment of long lived assets | — | | | 16,166 | | | 11,233 | | | 16,294 | |
| Gain on sale of property and equipment and assets of unconsolidated subsidiary | (1,011) | | | (83,559) | | | (1,329) | | | (143,461) | |
| General and administrative expenses | 27,445 | | | 35,365 | | | 85,835 | | | 100,565 | |
| Total Operating Expenses | 194,287 | | | 139,999 | | | 624,604 | | | 462,381 | |
| Operating Income (Loss) | (17,345) | | | 142,161 | | | (3,688) | | | 310,190 | |
| Other Income (Expense): | | | | | | | |
| Commodity derivatives gain (loss) | 87,956 | | | (35,913) | | | 39,383 | | | (175,752) | |
| Interest expense | (23,224) | | | (20,725) | | | (54,791) | | | (103,229) | |
| Other income | 1,337 | | | 1,827 | | | 3,332 | | | 3,094 | |
| Total Other Income (Expense) | 66,069 | | | (54,811) | | | (12,076) | | | (275,887) | |
| Income (Loss) Before Income Taxes | 48,724 | | | 87,350 | | | (15,764) | | | 34,303 | |
| Income tax expense | (14,800) | | | (22,200) | | | (900) | | | (12,300) | |
| Net Income (Loss) | $ | 33,924 | | | $ | 65,150 | | | $ | (16,664) | | | $ | 22,003 | |
The following table provides a summary of our sales volumes, average prices and operating expenses on a per BOE basis for the periods indicated:
| | | For the Three Months Ended | | | For the Nine Months Ended | | | For the Three Months Ended | | | For the Six Months Ended | |
| | September 30, | | | September 30, | | | June 30, | | | June 30, | |
| | 2019 | | 2018 | | 2019 | | 2018 | | 2020 | | 2019 | | 2020 | | 2019 |
| As restated | | | | As restated | | | |
| Sales (MBoe): | 7,390 | | | 6,963 | | | 22,167 | | | 19,855 | | |
Sales (MBoe)(1): | | Sales (MBoe)(1): | 8,322 | | | 7,540 | | | 16,899 | | | 14,776 | |
| Oil sales (MBbl) | Oil sales (MBbl) | 3,597 | | | 3,618 | | | 10,830 | | | 10,394 | | Oil sales (MBbl) | 3,419 | | | 3,650 | | | 6,923 | | | 7,233 | |
| Natural gas sales (MMcf) | Natural gas sales (MMcf) | 14,418 | | | 11,838 | | | 43,433 | | | 33,612 | | Natural gas sales (MMcf) | 17,543 | | | 15,055 | | | 36,546 | | | 29,015 | |
| NGL sales (MBbl) | NGL sales (MBbl) | 1,390 | | | 1,372 | | | 4,097 | | | 3,860 | | NGL sales (MBbl) | 1,979 | | | 1,380 | | | 3,885 | | | 2,707 | |
| Sales (BOE/d): | 80,327 | | | 75,680 | | | 81,198 | | | 72,731 | | |
Sales (BOE/d)(1): | | Sales (BOE/d)(1): | 91,451 | | | 82,856 | | | 92,852 | | | 81,635 | |
| Oil sales (Bbl/d) | Oil sales (Bbl/d) | 39,098 | | | 39,323 | | | 39,670 | | | 38,072 | | Oil sales (Bbl/d) | 37,571 | | | 40,113 | | | 38,038 | | | 39,962 | |
| Natural gas sales (Mcf/d) | Natural gas sales (Mcf/d) | 156,717 | | | 128,679 | | | 159,095 | | | 123,122 | | Natural gas sales (Mcf/d) | 192,780 | | | 165,445 | | | 200,802 | | | 160,302 | |
| NGL sales (Bbl/d) | NGL sales (Bbl/d) | 15,109 | | | 14,910 | | | 15,007 | | | 14,138 | | NGL sales (Bbl/d) | 21,747 | | | 15,168 | | | 21,346 | | | 14,956 | |
Average sales prices(1): | | |
| Oil sales (per Bbl) | $ | 41.99 | | | $ | 62.32 | | | $ | 46.31 | | | $ | 59.58 | | |
| Oil sales with derivative settlements (per Bbl) | 45.58 | | | 50.02 | | | 43.77 | | | 48.23 | | |
Average sales prices(2): | | Average sales prices(2): | |
Oil sales (per Bbl)(3) | | Oil sales (per Bbl)(3) | $ | 10.61 | | | $ | 50.72 | | | $ | 23.18 | | | $ | 48.46 | |
Oil sales with derivative settlements (per Bbl)(3) | | Oil sales with derivative settlements (per Bbl)(3) | 18.11 | | | 43.83 | | | 31.97 | | | 42.87 | |
| Natural gas sales (per Mcf) | Natural gas sales (per Mcf) | 1.17 | | | 1.95 | | | 1.71 | | | 1.99 | | Natural gas sales (per Mcf) | 0.91 | | | 1.44 | | | 1.05 | | | 1.98 | |
| Natural gas sales with derivative settlements (per Mcf) | Natural gas sales with derivative settlements (per Mcf) | 1.33 | | | 2.08 | | | 1.69 | | | 2.37 | | Natural gas sales with derivative settlements (per Mcf) | 1.24 | | | 1.53 | | | 1.32 | | | 1.88 | |
| NGL sales (per Bbl) | NGL sales (per Bbl) | 6.55 | | | 24.49 | | | 10.97 | | | 22.38 | | NGL sales (per Bbl) | 5.47 | | | 11.04 | | | 7.21 | | | 13.24 | |
| Average price (per BOE) | 23.94 | | | 40.53 | | | 28.01 | | | 38.91 | | |
| Average price with derivative settlements (per BOE) | 26.01 | | | 34.35 | | | 26.73 | | | 33.62 | | |
Average price (per BOE)(3) | | Average price (per BOE)(3) | 7.59 | | | 29.45 | | | 13.42 | | | 30.05 | |
Average price with derivative settlements (per BOE)(3) | | Average price with derivative settlements (per BOE)(3) | 11.35 | | | 26.30 | | | 17.60 | | | 27.09 | |
| Expense per BOE: | Expense per BOE: | | Expense per BOE: | |
| Lease operating expenses | Lease operating expenses | $ | 3.11 | | | $ | 2.91 | | | $ | 3.09 | | | $ | 3.11 | | Lease operating expenses | $ | 2.76 | | | $ | 3.13 | | | $ | 3.16 | | | $ | 3.08 | |
| Transportation and gathering | Transportation and gathering | 0.94 | | | 1.69 | | | 1.31 | | | 1.47 | | Transportation and gathering | 3.16 | | | 1.57 | | | 2.91 | | | 1.50 | |
| Production taxes | Production taxes | 1.31 | | | 3.10 | | | 2.09 | | | 3.34 | | Production taxes | 0.56 | | | 2.46 | | | 1.07 | | | 2.48 | |
| Exploration expenses | 1.79 | | | 1.59 | | | 1.48 | | | 1.07 | | |
| Exploration and abandonment expenses | | Exploration and abandonment expenses | 7.53 | | | 1.76 | | | 10.36 | | | 1.32 | |
| Depletion, depreciation, amortization and accretion | Depletion, depreciation, amortization and accretion | 15.56 | | | 15.41 | | | 15.89 | | | 15.63 | | Depletion, depreciation, amortization and accretion | 9.93 | | | 15.70 | | | 9.39 | | | 16.05 | |
| Impairment of long lived assets | — | | | 2.32 | | | 0.51 | | | 0.82 | | |
| General and administrative expenses | General and administrative expenses | 3.71 | | | 5.08 | | | 3.87 | | | 5.06 | | General and administrative expenses | 3.02 | | | 4.08 | | | 2.12 | | | 3.95 | |
Cash general and administrative expenses(2) | 2.18 | | | 2.58 | | | 2.10 | | | 2.50 | | |
Cash general and administrative expenses(4) | | Cash general and administrative expenses(4) | 2.71 | | | 2.10 | | | 1.97 | | | 2.06 | |
| Stock-based compensation | Stock-based compensation | 1.54 | | | 2.50 | | | 1.77 | | | 2.56 | | Stock-based compensation | 0.31 | | | 1.98 | | | 0.15 | | | 1.89 | |
| Total operating expenses per BOE | $ | 26.42 | | | $ | 32.10 | | | $ | 28.24 | | | $ | 30.50 | | |
Total operating expenses per BOE(5) | | Total operating expenses per BOE(5) | $ | 26.96 | | | $ | 28.70 | | | $ | 29.01 | | | $ | 28.38 | |
| | | |
| Production taxes as a percentage of revenue | | Production taxes as a percentage of revenue | 7.4 | % | | 8.4 | % | | 7.9 | % | | 8.3 | % |
(1)One BOE is equal to six Mcf of natural gas or one Bbl of oil or NGL based on an approximate energy equivalency. This is an energy content correlation and does not reflect a value or price relationship between the commodities.
(2)Average prices shown in the table reflect prices both before and after the effects of our settlements of commodity derivative contracts. Our calculation of such effects includes both gains and losses on settlements for commodity derivatives and amortization of premiums paid or received on options that settled during the period.
(2)(3)Includes amounts allocated to a satisfied performance obligation, recognized within oil sales for the three and six months ended June 30, 2020, pursuant to ASC 606, Revenue Recognition.
(4)Cash general and administrative expenses for the three and ninesix months ended SeptemberJune 30, 2019 includes2020 include expense of $1.9$0.3 million and $2.5 million, respectively, related to the terms of a separation agreementagreements with atwo former executive officer.officers. Excluding thisthese one-time expenseexpenses results in cash general and administrative expense per BOE of $1.92$2.68 and $2.01$1.82, respectively for the three and ninesix months ended SeptemberJune 30, 2019, respectively.2020.
(5)Excludes midstream operating expenses, impairment of long lived assets, gain on sale of property and equipment, and other operating expenses.
Three Months Ended SeptemberJune 30, 20192020 Compared to Three Months Ended SeptemberJune 30, 20182019
Oil sales revenues. Crude oil sales revenues decreased by $74.4$148.8 million to $151.1$36.3 million for the three months ended SeptemberJune 30, 20192020 as compared to crude oil sales of $225.5$185.1 million for the three months ended SeptemberJune 30, 2018.2019. A decrease in sales volumes between these periods contributed a $1.4$11.7 million negative impact, and a decrease in crude oil prices contributed a $73.1$137.1 million negative impact. For the three months ended SeptemberJune 30, 2019,2020, crude oil revenue decreased by approximately $22.2$3.9 million due to the impact of our updated strategy to emphasize free cash flowthe increase in 2020 and beyond, resulting in a decrease in future capital expenditures and rig counts, which decreased the future forecasted production and increased the forecasted deferral balance on one of our revenue contracts. Pursuant to ASC 606, the contract term impacts the amount of consideration that can be included in the transaction price, which reduced oil sales revenue.
For the three months ended SeptemberJune 30, 2019,2020, our crude oil sales averaged 39.137.6 MBbl/d. Our crude oil sales volume decreased by 1%231 to 3,5973,419 MBbl for the three months ended SeptemberJune 30, 20192020 compared to 3,6183,650 MBbl for the three months ended SeptemberJune 30, 2018.2019. The volume decrease is primarily due to the natural decline of our existing properties, partially offset by an increase in production from the completion of 13388 gross wells from OctoberJuly 1, 20182019 to SeptemberJune 30, 2019.2020.
The average price we realized on the sale of crude oil was $41.99$10.61 per Bbl for the three months ended SeptemberJune 30, 20192020 compared to $62.32$50.72 per Bbl for the three months ended SeptemberJune 30, 2018,2019, primarily due to changes in market prices for crude oil and the $22.2$3.9 million decrease of crude oil revenue explained above.
Natural gas sales revenues. Natural gas sales revenues decreased by $6.3$5.7 million to $16.8$16.0 million for the three months ended SeptemberJune 30, 20192020 as compared to natural gas sales revenues of $23.1$21.7 million for the three months ended SeptemberJune 30, 2018.2019. An increase in sales volumes between these periods contributed a $5.0$3.6 million positive impact, while a decrease in natural gas prices contributed a $11.3$9.3 million negative impact.
For the three months ended SeptemberJune 30, 2019,2020, our natural gas sales averaged 156.7192.8 MMcf/d. Natural gas sales volumes increased by 22%2,488 to 14,41817,543 MMcf for the three months ended SeptemberJune 30, 20192020 as compared to 11,83815,055 MMcf for the three months ended SeptemberJune 30, 2018.2019. The volume increase is primarily due to the completion of 13388 gross wells from OctoberJuly 1, 20182019 to SeptemberJune 30, 2019,2020, partially offset by the natural decline on existing producing properties.
The average price we realized on the sale of our natural gas was $1.17$0.91 per Mcf for the three months ended SeptemberJune 30, 20192020 compared to $1.95$1.44 per Mcf for the three months ended SeptemberJune 30, 2018,2019, primarily due to capacity constraintsa negative commodity price environment due to oversupply and a decrease in transporting the wet gas associated with crude oil production coupled with negative market conditions surrounding limited export capacity.demand.
NGL sales revenues. NGL sales revenues decreased by $24.5$4.4 million to $9.1$10.8 million for the three months ended SeptemberJune 30, 20192020 as compared to NGL sales revenues of $33.6$15.2 million for the three months ended SeptemberJune 30, 2018.2019. An increase in sales volumes between these periods contributed a $0.4$6.5 million positive impact, while a decrease in price contributed a $24.9$10.9 million negative impact.
For the three months ended SeptemberJune 30, 2019,2020, our NGL sales averaged 15.121.7 MBbl/d. NGL sales volumes increased by 1%599 to 1,3901,979 MBbl for the three months ended SeptemberJune 30, 20192020 as compared to 1,3721,380 MBbl for the three months ended SeptemberJune 30, 2018.2019. The volume increase is primarily due to the completion of 13388 gross wells from OctoberJuly 1, 20182019 to SeptemberJune 30, 2019,2020, partially offset by the natural decline on existing producing properties. Our NGL sales are directly associated with our natural gas sales because our natural gas volumes are processed by third parties for both residue natural gas sales and NGL sales.
The average price we realized on the sale of our NGL was $6.55$5.47 per Bbl for the three months ended SeptemberJune 30, 20192020 compared to $24.49$11.04 per Bbl for the three months ended SeptemberJune 30, 2018,2019, primarily due to capacity constraintsa negative commodity price environment due to oversupply and a decrease in transporting the wet gas associated with crude oil production coupled with negative market conditions surrounding limited export capacity.demand.
Lease operating expenses ("LOE").expenses. Our LOE increaseddecreased by $2.7$0.6 million to $23.0 million for the three months ended SeptemberJune 30, 2019,2020, from $20.3$23.6 million for the three months ended SeptemberJune 30, 2018.2019. The increasedecrease in LOE was primarily the result of an increasea decrease in producing wells and an increasea decrease in workover repairs, partially offset byin addition to optimization of our field cost structure during the twelvethree months ended SeptemberJune 30, 2019.
2020. On a per unit basis, LOE increaseddecreased to $3.11$2.76 per BOE sold for the three months ended SeptemberJune 30, 20192020 from $2.91$3.13 per BOE for the three months ended SeptemberJune 30, 2018.2019.
Transportation and gathering ("T&G"). Our T&G expense decreasedincreased by $4.9$14.4 million to $6.9$26.3 million for the three months ended SeptemberJune 30, 2019,2020, from $11.8$11.9 million for the three months ended SeptemberJune 30, 2018.2019. The decreaseincrease in T&G was primarily due to a decreasean increase of volumes on a certain gathering system during the three months ended SeptemberJune 30, 20192020 compared to the three months ended SeptemberJune 30, 2018.
2019. On a per unit basis, T&G decreasedincreased to $0.94$3.16 per BOE sold for the three months ended SeptemberJune 30, 20192020 compared to $1.69$1.57 per BOE sold for the three months ended SeptemberJune 30, 2018.2019.
Production taxes. Our production taxes decreased by $11.9$13.9 million to $9.7$4.7 million for the three months ended SeptemberJune 30, 20192020 as compared to $21.6$18.6 million for the three months ended SeptemberJune 30, 2018.2019. The decrease is primarily attributable to decreased revenue as production taxes are calculated as a percentage of sales revenue. Production taxes as a percentage of sales revenue was 5.5%7.4% for the three months ended SeptemberJune 30, 20192020 as compared to 7.7%8.4% for the three months ended SeptemberJune 30, 2018.2019. The decreaseconsistency in production taxes as a percentage of sales revenue relates to a decrease in thecomparatively constant estimated ad valorem and severance tax rates and an adjustment to the estimated ad valorem tax payable for the three months ended SeptemberJune 30, 2019.2020.
Exploration and abandonment expenses. Our exploration and abandonment expenses were $13.2$62.7 million for the three months ended SeptemberJune 30, 2019,2020, of which were primarily attributable to $0.5$62.6 million in expense for the extension of certain leases and $11.2 million in impairment expense relatedwas lease abandonment expense. Due to the abandonmentdecrease in pricing, property in our core field was abandoned and impairment of unproved properties for the three months ended September 30, 2019.impaired. For the three months ended SeptemberJune 30, 2018,2019, we recognized $11.0$13.3 million in exploration and abandonment expenses.
Depletion, depreciation, amortization and accretion expense ("DD&A").expense. Our DD&A expense increased $7.7decreased $35.8 million to $115.0$82.6 million for the three months ended SeptemberJune 30, 20192020 as compared to $107.3$118.4 million for the three months ended SeptemberJune 30, 2018. This increase is due to an increase in volumes sold for the three months ended September 30, 2019 as sales increased by approximately 427 MBoe.2019. On a per unit basis, DD&A expense increaseddecreased to $15.56$9.93 per BOE for the three months ended SeptemberJune 30, 20192020 from $15.41$15.70 per BOE for the three months ended SeptemberJune 30, 2018.2019. This decrease is due to an impairment of $1.3 billion of proved oil and gas properties that occurred during the fourth quarter of 2019.
Impairment of long lived assets. No impairment expense was recognized forFor the three months ended SeptemberJune 30, 2019. Impairment expense of $16.2 million2020 and 2019, impairment expense was recognized for the three months ended September 30, 2018$1.0 million and $3.0 million, respectively, related to impairment of the proved oil and gas properties in our northern field.
Gain on sale of property and equipment and assets of unconsolidated subsidiary. Our gain on sale of property and equipment and assets of unconsolidated subsidiary was $1.0 million forfield as the three months ended September 30, 2019. Our gain on sale of property and equipment and assets of unconsolidated subsidiary was $83.6 million related to our August 2018 Divestiture forfair value did not exceed the three months ended September 30, 2018.carrying amount associated with the properties.
General and administrative expenses ("G&A"). General and administrative expenses decreased by $8.0$5.6 million to $27.4$25.1 million for the three months ended SeptemberJune 30, 20192020 as compared to $35.4$30.7 million for the three months ended SeptemberJune 30, 2018.2019. This decrease is primarily due to reductions of workforce during the first and second quarters of 2020, and a decrease in stock-based compensation expense recognized for the three months ended SeptemberJune 30, 20192020 compared to the three months ended SeptemberJune 30, 2018.2019. On a per unit basis, G&A expense decreased to $3.71$3.02 per BOE sold for the three months ended SeptemberJune 30, 20192020 from $5.08$4.08 per BOE sold for the three months ended SeptemberJune 30, 2018.2019.
Our G&A expenses for the three months ended SeptemberJune 30, 20192020 includes $1.9$0.3 million related to the terms of a separation agreement with a former executive officer. No expenses of this nature were incurred during the three months ended SeptemberJune 30, 2018.2019.
Our G&A expenses include the non-cash expense for stock-based compensation for equity awards granted to our employees and directors. For the three months ended SeptemberJune 30, 2020, there was $2.6 million of stock-based compensation expense. For the three months ended June 30, 2019, and 2018, stock-based compensation expense was $11.4$14.9 million.
Other operating expenses. Other operating expenses were $13.2 million for the three months ended June 30, 2020. This amount is primarily made up of a $9.5 million early termination fee related to the termination of our crude oil marketing contract and $17.4$2.4 million respectively.incurred in standby rig fees.
Commodity derivative gain (loss). Primarily due to the effects of unwinding certain derivative instruments, partially offset by a decrease in NYMEX crude oil futures prices at SeptemberJune 30, 2020 as compared to December 31, 2019 and change in fair value from the execution of new positions, we incurred a net loss on our commodity derivatives of $69.3 million for the three months ended June 30, 2020. Primarily due to the increase in NYMEX crude oil futures prices at June 30, 2019 as compared to June 30, 2019December 31, 2018 and change in fair value from the execution of new positions, we incurred a net gain on our commodity derivatives of $88.0$73.5 million for the three months ended SeptemberJune 30, 2019, including the amortization of premiums. Primarily due to the increase in NYMEX crude oil futures prices at September 30, 2018 as compared to June 30, 2018 and change in fair value from the execution of new positions, we incurred a net loss on our commodity derivatives of $35.9 million for the three months ended September 30, 2018, including the amortization of premiums. These gains and losses are a result of our hedging program, which is used to mitigate our exposure to commodity price fluctuations. The fair value of the open commodity derivative instruments will continue to
change in value until the transactions are settled and we will likely
add to our hedging program in the future. Therefore, we expect our net income (loss) to reflect the volatility of commodity price forward markets. Our cash flow will only be affected upon settlement of the transactions at the current market prices at that time. During the three months ended SeptemberJune 30, 2019,2020, we received cash settlements ofsettled commodity derivatives totaling $16.1$127.4 million. During the three months ended SeptemberJune 30, 2018,2019, we paid cash settlements of commodity derivatives totaling $41.0$14.2 million.
Reorganization items, net. Due to the commencement of the Chapter 11 Cases during the second quarter of 2020, we have incurred and will continue to incur significant costs associated with the reorganization, primarily legal and professional fees. For the three months ended June 30, 2020, we recognized $26.9 million in reorganization items. No reorganization items were recognized during the same period in the preceding year. Please see to Note 5—Reorganization Items, Net in Part I, Item I, Financial Information of this Quarterly Report.
Interest expense. Interest expense consists of interest expense on our long-term debt and amortization of debt issuance costs, net of capitalized interest. For the three months ended SeptemberJune 30, 2019,2020, we recognized interest expense of $23.2$20.3 million as compared to $20.7$18.6 million for the three months ended SeptemberJune 30, 2018,2019, as a result of borrowings under our revolving credit facility,DIP Credit Facility, our Credit Facility, our 2024 Senior Notes, our 2026 Senior Notes and the amortization of debt issuance costs.
We incurred interest expense for the three months ended SeptemberJune 30, 20192020 of $23.8$20.2 million related to our 2024 Senior Notes, 2026 Senior Notes, Credit Facility and revolving credit facility.DIP Credit Facility. We incurred interest expense for the three months ended SeptemberJune 30, 20182019 of approximately $21.5$22.2 million related to our revolving credit facility,Credit Facility, our 2024 Senior Notes, and our 2026 Senior Notes. Also included in interest expense for the three months ended SeptemberJune 30, 20192020 and 20182019 was the amortization of debt issuance costs of $1.0$1.9 million and $0.9$1.3 million, respectively. For the three months ended SeptemberJune 30, 20192020 and 2018,2019, we capitalized interest expense of $1.6$1.9 million and $1.7$1.8 million, respectively. Interest expense for the three months ended June 30, 2019 also includes $3.2 million of gain on debt extinguishment upon the repurchase of our 2026 Senior Notes.
Income tax expense. We recorded anno income tax expense of $14.8 million and $22.2 million for the three months ended SeptemberJune 30, 20192020 and 2018, respectively.$15.1 million of income tax expense for the three months ended June 30, 2019. This resulted in an effective tax rate of approximately 30.4%zero and 25.4%25.8% for the three months ended SeptemberJune 30, 20192020 and 2018,2019, respectively. Our effective tax rate for the three months ended SeptemberJune 30, 20192020 and 20182019 differs from the U.S. statutory income tax rates of 21.0% primarily due to the effects of state income taxes, and estimated taxable permanent differences.differences, and valuation allowance.
Gathering and facilities segment. The Company hasPrior to March 31, 2020, we had two operating segments, (i) the exploration, development and production of oil, natural gas and NGL (the "exploration and production segment") and (ii) the construction, operation and support of midstream assets to gather and process crude oil and gas production (the "gathering and facilities segment"). PriorPlease see Note 1—Business and Organization — Deconsolidation of Elevation Midstream, LLC in Part I, Item I, Financial Information of this Quarterly Report for further information related to the fourth quarterdeconsolidation of 2018, the Company hadElevation Midstream, LLC. After March 31, 2020, Extraction began reporting as a single operatingreportable segment. The gathering systems and facilities operating segment was under development as of September 30, 2019. On October 3, 2019, Elevation commenced moving crude oil, natural gas and water through its Badger central gathering facility. Capital expenditures associated with gathering systems and facilities were incurred to develop midstream infrastructure to support the Company's development of its oil and gas leasehold along with third-party activity and amounted to $65.1 million and $37.5 million for the three months ended September 30, 2019 and 2018, respectively.
NineSix Months Ended SeptemberJune 30, 20192020 Compared to NineSix Months Ended SeptemberJune 30, 20182019
Oil sales revenues. Crude oil sales revenues decreased by $117.6$190.0 million to $501.6$160.5 million for the ninesix months ended SeptemberJune 30, 20192020 as compared to crude oil sales of $619.2$350.5 million for the ninesix months ended SeptemberJune 30, 2018. An increase2019. A decrease in sales volumes between these periods contributed a $26.0$15.0 million positivenegative impact, whileand a decrease in crude oil prices contributed a $143.6$175.0 million negative impact. For the ninesix months ended SeptemberJune 30, 20192020, crude oil revenue was decreased by approximately $22.2$12.3 million due to the impact of our updated strategy to emphasize free cash flowthe increase in 2020 and beyond, resulting in a decrease in future capital expenditures and rig counts, which decreased the future forecasted production and increased the forecasted deferral balance on one of our revenue contracts. Pursuant to ASC 606, the contract term impacts the amount of consideration that can be included in the transaction price, which reduced oil sales revenue.
For the ninesix months ended SeptemberJune 30, 2019,2020, our crude oil sales averaged 39.738.0 MBbl/d. Our crude oil sales volume increaseddecreased by 4% to 10,8306,923 MBbl for the ninesix months ended SeptemberJune 30, 20192020 compared to 10,3947,233 MBbl for the ninesix months ended SeptemberJune 30, 2018.2019. The volume increasedecrease is primarily due to the natural decline of our existing properties, partially offset by an increase in production from the completion of 13388 gross wells from OctoberJuly 1, 20182019 to SeptemberJune 30, 2019, partially offset by the natural decline of our existing properties.2020.
The average price we realized on the sale of crude oil was $46.31$23.18 per Bbl for the ninesix months ended SeptemberJune 30, 20192020 compared to $59.58$48.46 per Bbl for the ninesix months ended SeptemberJune 30, 2018,2019, primarily due to changes in market prices for crude oil and the $22.0$12.3 million decrease of crude oil revenue explained above.
Natural gas sales revenues. Natural gas sales revenues increaseddecreased by $7.4$19.3 million to $74.4$38.3 million for the ninesix months ended SeptemberJune 30, 20192020 as compared to natural gas sales revenues of $67.0$57.6 million for the ninesix months ended SeptemberJune 30, 2018.2019. An increase in sales volumes between these periods contributed a $19.5$14.9 million positive impact, while a decrease in natural gas prices contributed a $12.1$34.2 million negative impact.
For the ninesix months ended SeptemberJune 30, 2019,2020, our natural gas sales averaged 159.1200.8 MMcf/d. Natural gas sales volumes increased by 29%7,531 to 43,43336,546 MMcf for the ninesix months ended SeptemberJune 30, 20192020 as compared to 33,61229,015 MMcf for the ninesix months ended SeptemberJune 30, 2018.2019. The volume increase is primarily due to the completion of 13388 gross wells from OctoberJuly 1, 20182019 to SeptemberJune 30, 2019,2020, partially offset by the natural decline on existing producing properties.
The average price we realized on the sale of our natural gas was $1.71$1.05 per Mcf for the ninesix months ended SeptemberJune 30, 20192020 compared to $1.99$1.98 per Mcf for the ninesix months ended SeptemberJune 30, 2018,2019, primarily due to capacity constraints in transporting the wet gas associated with crude oil production coupled with a negative market conditions surrounding limited export capacity.commodity price environment due to oversupply and a decrease in demand.
NGL sales revenues. NGL sales revenues decreased by $41.5$7.8 million to $44.9$28.0 million for the ninesix months ended SeptemberJune 30, 20192020 as compared to NGL sales revenues of $86.4$35.8 million for the ninesix months ended SeptemberJune 30, 2018.2019. An increase in sales volumes between these periods contributed a $5.3$15.5 million positive impact, while a decrease in price contributed a $46.7$23.3 million negative impact.
For the ninesix months ended SeptemberJune 30, 2019,2020, our NGL sales averaged 15.021.3 MBbl/d. NGL sales volumes increased by 6%1,178 to 4,0973,885 MBbl for the ninesix months ended SeptemberJune 30, 20192020 as compared to 3,8602,707 MBbl for the ninesix months ended SeptemberJune 30, 2018.2019. The volume increase is primarily due to the completion of 13388 gross wells from OctoberJuly 1, 20182019 to SeptemberJune 30, 2019,2020, partially offset by the natural decline on existing producing properties. Our NGL sales are directly associated with our natural gas sales because our natural gas volumes are processed by third parties for both residue natural gas sales and NGL sales.
The average price we realized on the sale of our NGL was $10.97$7.21 per Bbl for the ninesix months ended SeptemberJune 30, 20192020 compared to $22.38$13.24 per Bbl for the ninesix months ended SeptemberJune 30, 2018,2019, primarily due to capacity constraints in transporting the wet gas associated with crude oil production coupled with a negative market conditions surrounding limited export capacity.commodity price environment due to oversupply and a decrease in demand.
Lease operating expenses. Our LOE increased by $6.6$7.9 million to $68.4$53.4 million for the ninesix months ended SeptemberJune 30, 2019,2020, from $61.8$45.5 million for the ninesix months ended SeptemberJune 30, 2018.2019. The increase in LOE was primarily the result of an increase in producing wells and an increase in workover repairs, partially offset by optimization of our field cost structure during the twelvesix months ended SeptemberJune 30, 2020. On a per unit basis, LOE increased to $3.16 per BOE sold for the six months ended June 30, 2020 from $3.08 per BOE for the six months ended June 30, 2019.
On a per unit basis, LOE decreased to $3.09 per BOE sold for the nine months ended September 30, 2019 from $3.11 per BOE for the nine months ended September 30, 2018. The decrease in LOE per BOE is primarily a result of increased production volumes during the nine months ended September 30, 2019.
Transportation and gathering.gathering ("T&G"). Our T&G expense decreasedincreased by $0.2$26.9 million to $29.1$49.1 million for the ninesix months ended SeptemberJune 30, 2019,2020, from $29.3$22.2 million for the ninesix months ended SeptemberJune 30, 2018.2019. The decreaseincrease in T&G was primarily due to a decreasean increase of volumes on a certain gathering system forduring the ninesix months ended SeptemberJune 30, 2020 compared to the six months ended June 30, 2019.
On a per unit basis, T&G decreasedincreased to $1.31$2.91 per BOE sold for the ninesix months ended SeptemberJune 30, 20192020 compared to $1.47$1.50 per BOE sold for the ninesix months ended SeptemberJune 30, 2018.2019.
Production taxes. Our production taxes decreased by $19.9$18.6 million to $46.4$18.1 million for the ninesix months ended SeptemberJune 30, 20192020 as compared to $66.3$36.7 million for the ninesix months ended SeptemberJune 30, 2018.2019. The decrease is primarily attributable to decreased revenue as production taxes are calculated as a percentage of sales revenue. Production taxes as a percentage of sales revenue was 7.5%7.9% for the ninesix months ended SeptemberJune 30, 20192020 as compared to 8.6%8.3% for the ninesix months ended SeptemberJune 30, 2018.2019. The decreaseconsistency in production taxes as a percentage of sales revenue relates to a decrease in thecomparatively constant estimated ad valorem and severance tax rates and an adjustment to the estimated ad valorem tax payable for the ninesix months ended SeptemberJune 30, 2019.2020.
Exploration and abandonment expenses. Our exploration and abandonment expenses were $32.7$175.1 million for the ninesix months ended SeptemberJune 30, 2020, of which $169.6 million was lease abandonment expense. Due to the decrease in pricing, all of the unproved property in our northern field was abandoned and impaired in the first quarter of 2020. For the six months ended June 30, 2019, which were primarily attributable to $2.0we recognized $19.5 million in expense for the extension of certain leasesexploration and $26.2 million in impairment expense related to the abandonment and impairment of unproved properties for the nine months ended September 30, 2019. For the nine months ended September 30, 2018, we recognized $21.3 million in exploration expenses.
Depletion, depreciation, amortization and accretion expense. Our DD&A expense increased $41.8decreased $78.4 million to $352.1$158.7 million for the ninesix months ended SeptemberJune 30, 20192020 as compared to $310.3$237.1 million for the ninesix months ended SeptemberJune 30, 2018. This increase is due to an increase in volumes sold for the nine months ended September 30, 2019 as sales increased by
approximately 2,312 MBoe.2019. On a per unit basis, DD&A expense increaseddecreased to $15.89$9.39 per BOE for the ninesix months ended SeptemberJune 30, 20192020 from $15.63$16.05 per BOE for the ninesix months ended SeptemberJune 30, 2018.2019. This decrease is due to an impairment of $1.3 billion of proved oil and gas properties that occurred during the fourth quarter of 2019.
Impairment of long lived assets. OurFor the six months ended June 30, 2020 and 2019, impairment expense ofwas $1.7 million and $11.2 million, for the nine months ended September 30, 2019 wasrespectively, related to impairment of the proved oil and gas properties in our northern field. Thefield as the fair value did not exceed ourthe carrying amount associated with the proved oil and gas properties in our northern field. Impairment expense of $16.3 million was recognized for the nine months ended September 30, 2018.
Gain on sale of property and equipment and assets of unconsolidated subsidiary. Our gain on sale of property and equipment and assets of unconsolidated subsidiary for the nine months ended September 30, 2019 was $1.3 million. Our gain on sale of property and equipment and assets of unconsolidated subsidiary was $143.5 million related to our April 2018 Divestitures and August 2018 Divestiture for the nine months ended September 30, 2018.properties.
General and administrative expenses.expenses ("G&A"). General and administrative expenses decreased by $14.8$22.7 million to $85.8$35.7 million for the ninesix months ended SeptemberJune 30, 20192020 as compared to $100.6$58.4 million for the ninesix months ended SeptemberJune 30, 2018.2019. This decrease is primarily due to reductions of workforce during the first and second quarters of 2020, and a decrease in stock-based compensation expense recognized for the ninesix months ended SeptemberJune 30, 20192020 compared to the ninesix months ended SeptemberJune 30, 2018.2019. On a per unit basis, G&A expense decreased to $3.87$2.12 per BOE sold for the ninesix months ended SeptemberJune 30, 20192020 from $5.06$3.95 per BOE sold for the ninesix months ended SeptemberJune 30, 2018.2019.
Our G&A expenses for the ninesix months ended SeptemberJune 30, 20192020 includes $1.9$2.5 million related to the terms of a separation agreementagreements with atwo former executive officer.officers. No expenses of this nature were incurred during the ninesix months ended SeptemberJune 30, 2018.2019.
Our G&A expenses include the non-cash expense for stock-based compensation for equity awards granted to our employees and directors. For the ninesix months ended SeptemberJune 30, 2020, there was $2.6 million of stock-based compensation expense. For the six months ended June 30, 2019, and 2018, stock-based compensation expense was $39.3$27.9 million.
Other operating expenses. Other operating expenses were $65.8 million for the six months ended June 30, 2020. This amount is primarily made up of a $46.8 million loss contingency from an alleged breach in contract stemming from a purported failure to complete the pipeline extensions connecting certain wells to the Badger central gathering facility prior to April 1, 2020, and $50.9a $9.5 million respectively.early termination fee related to the termination of our crude oil marketing contract. Also included in this amount is a $7.1 million charge to income for expenses related to a workforce reduction in February and May 2020.
Commodity derivative gain (loss). Primarily due to the decrease in NYMEX crude oil futures prices at SeptemberJune 30, 2020 as compared to December 31, 2019 and change in fair value from the execution of new positions, we incurred a net gain on our commodity derivatives of $193.7 million for the six months ended June 30, 2020. Primarily due to the increase in NYMEX crude oil futures prices at June 30, 2019 as compared to December 31, 2018 and change in fair value from the execution of new positions, we incurred a net gainloss on our commodity derivatives of $39.4$48.6 million for the ninesix months ended SeptemberJune 30, 2019, including the amortization of premiums. Primarily due to the increase in NYMEX crude oil futures prices at September 30, 2018 as compared to December 31, 2017These gains and change in fair value from the execution of new positions, we incurred a net loss on our commodity derivatives of $175.8 million for the nine months ended September 30, 2018, including the amortization of premiums. These losses are a result of our hedging program, which is used to mitigate our exposure to commodity price fluctuations. The fair value of the open commodity derivative instruments will continue to change in value until the transactions are settled and we will likely add to our hedging program in the future. Therefore, we expect our net income (loss) to reflect the volatility of commodity price forward markets. Our cash flow will only be affected upon settlement of the transactions at the current market prices at that time. During the ninesix months ended SeptemberJune 30, 2020, we settled commodity derivatives totaling $166.7 million. During the six months ended June 30, 2019, and 2018, we paid cash settlements of commodity derivatives totaling $8.4$24.5 million.
Loss on deconsolidation of Elevation Midstream, LLC. On March 16, 2020, we deconsolidated Elevation Midstream, LLC. Upon deconsolidation, we elected the fair value option to remeasure the Elevation equity method investment and determined it had no fair value. The Company recorded a $73.1 million loss on deconsolidation of
Elevation Midstream, LLC in the condensed consolidated statements of operations for the six months ended June 30, 2020.
Reorganization items, net. Due to the commencement of the Chapter 11 Cases during the second quarter of 2020, we have incurred and $99.9will continue to incur significant costs associated with the reorganization, primarily legal and professional fees. For the six months ended June 30, 2020, we recognized $26.9 million respectively.in reorganization items. No reorganization items were recognized during the same period in the preceding year. Please see to Note 5—Reorganization Items, Net in Part I, Item I, Financial Information of this Quarterly Report.
Interest expense. Interest expense consists of interest expense on our long-term debt and amortization of debt issuance costs, net of capitalized interest. For the ninesix months ended SeptemberJune 30, 2019,2020, we recognized interest expense of $54.8$41.7 million as compared to $103.2$31.6 million for the ninesix months ended SeptemberJune 30, 2018,2019, as a result of borrowings under our revolving credit facility,DIP Credit Facility, our 2021 Senior Notes,Credit Facility, our 2024 Senior Notes, our 2026 Senior Notes and the amortization of debt issuance costs.
We incurred interest expense for the ninesix months ended SeptemberJune 30, 20192020 of $66.9$42.5 million related to our 2024 Senior Notes, 2026 Senior Notes, Credit Facility and revolving credit facility.DIP Credit Facility. We incurred interest expense for the ninesix months ended SeptemberJune 30, 20182019 of approximately $61.6$43.0 million related to our revolving credit facility,Credit Facility, our 2021 Senior Notes, 2024 Senior Notes, and our 2026 Senior Notes, as well as a make-whole premium of $35.6 million related to our repayment of 2021 Senior Notes in January and February 2018.Notes. Also included in interest expense for the ninesix months ended SeptemberJune 30, 20192020 and 20182019 was the amortization of debt issuance costs of $3.8$3.2 million and $12.3$2.8 million, respectively. Amortization expense forFor the ninesix months ended SeptemberJune 30, 2018 includes $9.4 million of acceleration of amortization expense upon the repayment of the 2021 Senior Notes. For the nine months ended September 30,2020 and 2019, and 2018, we capitalized interest expense of $5.4$4.0 million and $6.3$3.8 million, respectively. Interest expense for the ninesix months ended SeptemberJune 30, 2019 also includes $10.5 million of gain on debt extinguishment upon the repurchase of our 2026 Senior Notes.
Income tax expense.(expense) benefit. We recorded an income tax expense of $0.9 million and $12.3$2.2 million for the ninesix months ended SeptemberJune 30, 20192020 and 2018, respectively.income tax benefit of $13.9 million for the six months ended June 30, 2019. This resulted in an effective tax rate of approximately negative 5.7%(0.8)% and 35.9%21.6% for the ninesix months ended SeptemberJune 30, 20192020 and 2018,2019, respectively. Our effective tax rate for the ninesix months ended SeptemberJune 30, 20192020 and 20182019 differs from the U.S. statutory income tax rates of 21.0% primarily becausedue to the effects of state income taxes, and estimated taxable permanent differences. The primary differences, between the tax rate of negative 5.7% and 35.9% for the nine months ended September 30, 2019 and 2018, respectively, are the increase in estimated permanent differences during the nine months ended September 30, 2019 compared to the nine months ended September 30, 2018 and the pre-tax book loss generated for the nine months ended September 30, 2019 compared to pre-tax book income for the nine months ended September 30, 2018.valuation allowance.
Gathering and facilities segment. The Company hasPrior to March 31, 2020, we had two operating segments, (i) the exploration, development and production of oil, natural gas and NGL (the "exploration and production segment") and (ii) the construction, operation and support of midstream assets to gather and process crude oil and gas production (the "gathering and facilities segment"). PriorPlease see Note 1—Business and Organization — Deconsolidation of Elevation Midstream, LLC in Part I, Item I, Financial Information of this Quarterly Report for further information related to the fourth quarterdeconsolidation of 2018, the Company had a single operating segment. The gathering systems and facilities operating segment was under development as of September 30, 2019. OnElevation Midstream, LLC.
In October 3, 2019, Elevation commenced moving crude oil, natural gas and water through its Badger central gathering facility. Capital expenditures associated withBecause Elevation had no revenue and insignificant operating expenses for the three and six months ended June 30, 2019, comparison to the three and six months ended June 30, 2020 is not relevant. Extraction's condensed consolidated statements of operations for the three months ended June 30, 2020 did not contain any Elevation activity due to their deconsolidation on March 16, 2020. The following amounts were incurred entirely during the first quarter of 2020, but are still part of amounts six months ended June 30, 2020. During the first quarter of 2020, the gathering systems and facilities are being incurred to develop midstream infrastructure to support the Company's developmentsegment had revenues of its oil and gas leasehold along with third-party activity and amounted to $192.6$6.0 million and $57.2direct operating expenses of $3.9 million. General and administrative expenses were $0.7 million for the ninesix months ended SeptemberJune 30, 20192020 and 2018, respectively. $2.0 million for the six months ended June 30, 2019. Depreciation expense was $1.1 million during the first quarter of 2020 as the gathering facility was placed into service during the fourth quarter of 2019. Please see Note 16—Segments in Part I, Item I, Financial Information of this Quarterly Report.
Liquidity and Capital Resources
Our primary sourcesChapter 11 Cases and Effect of Automatic Stay
On June 14, 2020, we filed for relief under chapter 11 of the Bankruptcy Code. The commencement of a voluntary proceeding in bankruptcy constituted an immediate event of default under the Credit Agreement and the indentures governing our Senior Notes, resulting in the automatic and immediate acceleration of all of our outstanding debt under the Credit Agreement and the Senior Notes. Any efforts to enforce payment obligations related to the acceleration of our debt have been automatically stayed as a result of the filing of the Chapter 11 Cases, and the creditors’ rights of enforcement are subject to the applicable provisions of the Bankruptcy Code. On June 14, 2020, we also entered into the RSA with certain holders of our Senior Notes to support a restructuring in accordance with the terms set forth therein. As more fully disclosed in Note 1—Business and Organization and Note 6—Long-Term Debt in Part I, Item 1. Financial Information of this Quarterly Report, the RSA contemplates a financial restructuring which would provide for the treatment of holders of certain claims and existing equity interests.
We expect to continue operations in the ordinary course for the duration of the Chapter 11 Cases. To ensure ordinary course operations, we have obtained approval from the Bankruptcy Court of the First Day Motions to continue our ordinary course operations after the filing date. In addition, we have obtained a DIP Credit Facility to fund operations during the bankruptcy proceedings. However, for the duration of the Chapter 11 Cases, our operations and our ability to develop and execute our business plan are subject to a high degree of risk and uncertainty associated with the Chapter 11 Cases. The outcome of the Chapter 11 Cases is dependent upon factors that are outside of our control, including actions of the Bankruptcy Court and our creditors. The significant risks and uncertainties related to our liquidity and capital resources areChapter 11 Cases described above raise substantial doubt about our ability to continue as a going concern. There can be no assurance that we will confirm and consummate a Restructuring Plan as contemplated by the RSA or complete another plan of reorganization with respect to the Chapter 11 Cases. As a result, we have concluded that management’s plans do not alleviate substantial doubt about our ability to continue as a going concern.
As a result of the Chapter 11 Cases, our total available liquidity as of June 30, 2020 consisted of cash flowson hand of $62.6 million. We expect to continue using additional cash that will further reduce this liquidity. With the Bankruptcy Court’s authorization of the Final DIP Order on July 20, 2020, we obtained access to an additional $35.0 million under the DIP Credit Facility as is described in Note 6—Long-Term Debt in Part I, Item 1. Financial Information of this Quarterly Report. With cash on hand and DIP Credit Facility availability, we believe that we will have sufficient liquidity, including funds generated by operating activitiesfrom ongoing operations, to fund anticipated cash requirements through the Chapter 11 Cases. As such, we expect to pay vendor and borrowings underroyalty obligations on a go-forward basis according to the terms of our revolving credit facility. Depending upon market conditionscurrent contracts and other factors, we may also issue equityconsistent with applicable court orders, if any, approving such payments.
Sources of Liquidity and debt securities if needed.Capital Resources
Historically, our primary sources of liquidity have been borrowings under our revolving credit facility,Credit Facility, proceeds from notes offerings and preferred stock offerings, equity provided by investors, including our management team, cash from the IPO and Private Placement, cash from the issuance of preferred units,stock, and cash flows from operationsdivestitures and divestitures. To date, ourfrom the sale of oil, gas and NGL production. Our primary useuses of capital hashave been for the acquisition of oil and gas properties to increase our acreage position, as well as development and exploration of oil and gas properties. As of June 30, 2020, our DIP Credit Facility borrowings were $15.0 million, with $37.5 million total outstanding including amounts that were rolled over from the Credit Facility. Our Credit Facility borrowings net of unamortized debt issuance costs, were approximately $1,635.2$481.9 million and $1,417.7$470.0 million at SeptemberJune 30, 2019,2020, and December 31, 2018,2019, respectively. We had senior notes totaling $1.1 billion outstanding at June 30, 2020 and December 31, 2019. We also have other contractual commitments, which are described in Note 11 – 14—Commitments and Contingencies in Part I, Item I,1, Financial Information of this Quarterly Report.
We may from timeWith the Bankruptcy Court’s authorization of the DIP Credit Facility, we believe that we have sufficient liquidity to time seek to retire or purchaseexecute our outstanding notesbusiness plan through cash purchases and/or exchanges (including for equity securities), in open market purchases, privately negotiated transactions or otherwise. Such repurchases or exchanges, if any, will depend on prevailing market conditions, our liquidity requirements, contractual restrictions and other factors. The amounts involved may be material.the bankruptcy proceedings.
We plan to continue our practice of entering into hedging arrangements to reduce the impact of commodity price volatility on our cash flow from operations. Under this strategy, we intend to enter into commodity derivative contracts at times and on terms desired to maintain a portfolio of commodity derivative contracts covering approximately
50% to 70% of our projected oil and natural gas production over a one to two year period at a given point in time, although we may from time to time hedge more or less than this approximate range.
Based on current expectations, we believe we have sufficient liquidity through our existing cash balances, cash flow from operations and available borrowings under our revolving credit facility to execute our current capital program, excluding any acquisitions we may consummate, make our interest payments on the 2024 Senior Notes, 2026 Senior Notes and credit facility and pay dividends on our Series A Preferred Stock and the Elevation Preferred Units.
If cash flow from operations does not meet our expectations, we may reduce our expected level of capital expenditures and/or fund a portion of our capital expenditures using borrowings under our revolving credit facility, issuances of debt and equity securities or from other sources, such as asset sales. We cannot assure you that necessary capital will be available on acceptable terms or at all. Our ability to raise funds through the incurrence of additional indebtedness could be limited by the covenants in our debt arrangements. If we are unable to obtain funds when needed or on acceptable terms, we may not be able to complete acquisitions that may be favorable to us or finance the capital expenditures necessary to maintain our production or proved reserves.
In October 2019, we revised our 2019 capital budget for the drilling and completion of operated and non-operated wells from a range of $585.0 million to $675.0 million to approximately $520.0 million to $550.0 million. We intend to allocate substantially all our capital budget to the Core DJ Basin. We expected to drill 125 gross operated wells, complete 122 gross operated wells and turn-in-line 111 gross operated wells. As a result of the change in our capital budget, we expect to drill 108 gross operated wells, complete 118 gross operated wells and turn-in-line 113 gross operated wells. Our capital budget still anticipates a one to two operated rig drilling program and excludes up to $250.0 million for Elevation, which is fully funded by a third party and any amounts that may be paid for potential acquisitions.
The Company had a Stock Repurchase Program that ended in place during2019. During the ninesix months ended SeptemberJune 30, 2019. Spending2019, spending under this program during this time period was $136.9 million, and the total amount repurchased under the program was $163.2 million which is the full amount authorized to be repurchased. The Company$115.7 million. We also hashad a Senior Notes Repurchase Program in place. Spending under this program during the ninesix months ended SeptemberJune 30, 2019 was $39.3 million. The Company is authorized to repurchase up to $100.0 million of itsNo common stock or Senior Notes.Notes were repurchased during the six months ended June 30, 2020.
Cash Flows
The following table summarizes our cash flows for the periods indicated (in thousands):
| | | | | | | | | | | |
| For the Nine Months Ended | | |
| September 30, | | |
| 2019 | | 2018 |
| Net cash provided by operating activities | $ | 356,561 | | | $ | 468,362 | |
| Net cash used in investing activities | $ | (706,868) | | | $ | (678,133) | |
| Net cash provided by financing activities | $ | 173,049 | | | $ | 477,068 | |
| | | | | | | | | | | |
| For the Six Months Ended | | |
| June 30, | | |
| 2020 | | 2019 |
| Net cash provided by operating activities | $ | 83,954 | | | $ | 218,444 | |
| Net cash used in investing activities | $ | (191,413) | | | $ | (449,244) | |
| Net cash provided by financing activities | $ | 145,358 | | | $ | 31,721 | |
NineSix Months Ended SeptemberJune 30, 20192020 Compared to NineSix Months Ended SeptemberJune 30, 20182019
Net cash provided by operating activities. For the ninesix months ended SeptemberJune 30, 20192020 as compared to the ninesix months ended SeptemberJune 30, 2018,2019, our net cash provided by operating activities decreased by $111.8$134.5 million primarily due to athe decrease in operating revenues net of expenses of $139.0$235.8 million primarily as a result of a decrease in commodity prices along withand a decrease of $90.5$18.7 million in cash paid for interest offset by an increase of $80.6 million related to changes in working capital and an increase in cash paid for interest of $5.2 million. These decreases in net cash provided by operating activities were partially offset by a $75.0$87.4 million decrease in commodity derivative settlement payments.
Net cash used in investing activities. For the ninesix months ended SeptemberJune 30, 2019 as compared to the nine months ended September 30, 2018, our2020, net cash used in investing activities increaseddecreased by $28.7$257.8 million compared to the six months ended June 30, 2019 primarily due to increased spendingas a result of $127.8$121.6 million less spent on ouroil and gas property additions, $119.5 million less spent on gathering systems and facilities, a $20.6$21.8 million increase inless spent on other property and equipment a $30.4and $4.9 million increase from the sale of property and equipment and a $16.5 million increase in spendingless spent on our investment in unconsolidated subsidiaries. Additionally, we did not receive $82.6 million in the current periodProceeds from the sale of an unconsolidated subsidiary. These increases were offset by a decreaseassets was $8.8 million less during the first six months of 2020 than during the same period in spending on oil and gas property additions of $248.6 million for the nine months ended September 30, 2019.
Net cash provided by financing activities. For the ninesix months ended SeptemberJune 30, 2019 as compared to the nine months ended September 30, 2018, our2020, net cash provided by financing activities decreased by $304.0was $113.6 million more than for the six months ended June 30, 2019 primarily as a result of a decrease of $739.7$116.5 million from the issuance of the 2026 Senior Notes, partially offset by an increase from redemption of the 2021 Senior Notes for $585.6 million. Net borrowings on the revolver increased $65.0 million offset by a $49.5 million decrease in the cash received from the issuance of Elevation Preferred Units compared to the nine months ended September 30, 2019. Additionally, there was an increase in cash spent to repurchase common stock, of $133.3 million, as result of our Share Repurchase Program, and senior notes of $39.3 million as a result of ourspent to repurchase 2026 Senior Note Repurchase ProgramNotes and $5.4 million spent on Preferred Stock Dividends during the ninefirst six months ended September 30,of 2019 which were not spent during first six months of 2020. Also, net borrowings on the Credit Facility and DIP Credit Facility during the first six months of 2020 were $49.5 million less compared to the first six months of 2019.
Working Capital
Our working capital deficit was $193.2$322.1 million and $240.8 million at SeptemberJune 30, 20192020 and our surplus was $62.2 million at December 31, 2018.2019, respectively. However, as of June 30, 2020, many of our current liabilities were classified as liabilities subject to compromise. Our cash balances totaled $57.7$62.6 million and $235.0$32.4 million at SeptemberJune 30, 20192020 and December 31, 2018,2019, respectively.
Due to the amounts that we incur related to our drilling and completion program and the timing of such expenditures, we may incur working capital deficits in the future. We expect that our cash flows from operating activities and availability under our revolving credit facility will be sufficient to fund our working capital needs. We expect that our pace of development, production volumes, commodity prices and differentials to NYMEX prices for our oil, natural gas and NGL production will be the largest variables affecting our working capital.capital along with reorganization costs pertaining to the bankruptcy. As part of the Chapter 11 Cases, the Company filed a motion to reject its drilling rig contracts. As such, the Company recorded $6.7 million in liabilities subject to compromise on the condensed consolidated balance sheets as of June 30, 2020 and in
reorganization items, net on the condensed consolidated statements of operations. Please see Note 14—Commitments and Contingencies and Note 1—Business and Organization — Ability to Continue as a Going Concern in Part I, Item 1. Financial Information of this Quarterly Report.
Debt Arrangements
As of September 30, 2019, our revolving credit facility has a maximum credit amount of $1.5 billion, subject to a borrowing base of $1.1 billion, subject to the current elected commitments of $1.0 billion, and certainFor details of our currentdebt arrangements including our DIP Credit Facility, Credit Facility, 2024 Senior Notes and future subsidiaries are or will be guarantors under such facility. Amounts repaid under our revolving credit facility may be re-borrowed from time to time, subject to the terms of the facility. For more information on the revolving credit facility,2026 Senior Notes, please see Note 4 — 6—Long-Term Debt in Part 1,I, Item 1. Financial Information of this Quarterly Report. The revolving credit facility is secured by liens on substantially all of our properties.Additional debt disclosures specific to this Management Discussion and Analysis section are as follows.
In July 2016, we closed a private offering of our 2021 Senior Notes that resulted in net proceeds of approximately $537.2 million. Our 2021 Senior Notes bore interest at an annual rate of 7.875%. Interest on our 2021 Senior Notes was payable on January 15 and July 15 of each year, and the first interest payment was made on January 15, 2017. Our 2021 Senior Notes would have matured on July 15, 2021. Our 2021 Senior Notes were guaranteed by all of our current and future restricted subsidiaries (other than Extraction Finance Corp., the co-issuer of our 2021 Senior Notes). In the first quarter of 2018, we closed a tender offer for the 2021 Senior Notes and subsequently redeemed all remaining outstanding 2021 Senior Notes. No 2021 Senior Notes remain outstanding.
In August 2017, we closed a private offering of our 2024 Senior Notes that resulted in net proceeds of approximately $392.6 million. Our 2024 Senior Notes bear interest at an annual rate of 7.375%. Interest on our 2024 Senior Notes is payable on May 15 and November 15 of each year, and the first interest payment was made on November 15, 2017. Our 2024 Senior Notes will mature on May 15, 2024. Our 2024 Senior Notes are guaranteed by certain of our current subsidiaries and by certain future restricted subsidiaries that guarantee our indebtedness under a credit facility.
In January 2018, we closed a private offering of our 2026 Senior Notes that resulted in net proceeds of approximately $737.9 million. Our 2026 Senior Notes bear interest at an annual rate of 5.625%. Interest on our 2026 Senior Notes is payable on February 1 and August 1 of each year, and the first interest payment was made on August 1, 2018. Our 2026 Senior Notes will mature on February 1, 2026. Our 2026 Senior Notes are guaranteed by certain of our current subsidiaries and by certain future restricted subsidiaries that guarantee our indebtedness under a credit facility.
Revolving Credit Facility
The amount available to be borrowed under our revolving credit facility is subject to a borrowing base that is redetermined semiannually on each May 1 and November 1, and will depend on the volumes of our proved oil and gas reserves and estimated cash flows from these reserves and other information deemed relevant by the administrative agent under our revolving credit facility. As of September 30, 2019, the borrowing base was $1.1 billion, subject to current elected commitments of $1.0 billion.
On November 4, 2019, we amended our revolving credit facility to decrease the borrowing base from $1.1 billion to $950.0 million, associated with the scheduled borrowing base redetermination. The current elected commitments were also decreased to $950.0 million.
Principal amounts borrowed will be payable on the maturity date, and interest will be payable quarterly for alternate base rate loans and at the end of the applicable interest period for Eurodollar loans. We have a choice of borrowing in Eurodollars or at the alternate base rate. Eurodollar loans bear interest at a rate per annum equal to an adjusted LIBOR rate (equal to the product of: (a) the LIBOR rate, multiplied by (b) a fraction (expressed as a decimal), the numerator of which is the number one and the denominator of which is the number one minus the reserve percentages (expressed as a decimal) on such date at which the administrative agent under our revolving credit facility is required to maintain reserves on ‘Eurocurrency Liabilities’ as defined in and pursuant to Regulation D of the Board of Governors of the Federal Reserve System) plus an applicable margin ranging from 200 to 300 basis points, depending on the percentage of our borrowing base utilized. Alternate base rate loans bear interest at a rate per annum equal to the greatest of (i) the agent bank’s reference rate, (ii) the federal funds effective rate plus 50 basis points and (iii) the adjusted one-month LIBOR rate (as calculated above) plus 100 basis points, plus
an applicable margin ranging from 100 to 200 basis points, depending on the percentage of our borrowing base utilized. As of September 30, 2019, we had $550.0 million of outstanding borrowings under our revolving credit facility. We may repay any amounts borrowed prior to the maturity date without any premium or penalty other than customary LIBOR breakage costs.
The revolving credit facility is secured by liens on substantially all of our properties and guarantees from us and our current and future subsidiaries, with the exception of Elevation. The revolving credit facility contains restrictive covenants that may limit our ability to, among other things:
•incur additional indebtedness;
•sell assets;
•make loans to others;
•make investments;
•make certain changes to our capital structure;
•make or declare dividends;
•hedge future production or interest rates;
•enter into transactions with our affiliates;
•incur liens; and
•engage in certain other transactions without the prior consent of the lenders.
The revolving credit facility requires us to maintain the following financial ratios:
•a current ratio, which is the ratio of our and our restricted subsidiaries' consolidated current assets (includes unused commitments under our revolving credit facility and excludes derivative assets) to our restricted subsidiaries' consolidated current liabilities (excludes obligations under our revolving credit facility, the senior notes and certain derivative liabilities), of not less than 1.0 to 1.0 as of the last day of any fiscal quarter; and
•a net leverage ratio, which is the ratio of (i) consolidated debt less cash balances to (ii) our consolidated EBITDAX for the four fiscal quarter period most recently ended, not to exceed 4.0 to 1.0 as of the last day of such fiscal quarter.
2021 Senior Notes
In July 2016, we closed a private offering of our 2021 Senior Notes that resulted in net proceeds of approximately $537.2 million. Our 2021 Senior Notes bore interest at an annual rate of 7.875% and would have matured on July 15, 2021.
Concurrent with the 2026 Senior Notes Offering, we commenced a cash tender offer to purchase any and all of our 2021 Senior Notes. On January 24, 2018 we received approximately $500.6 million aggregate principal amount of the 2021 Senior Notes which were validly tendered (and not validly withdrawn). As a result, on January 25, 2018 we made a cash payment of approximately $534.2 million, which included principal of approximately $500.6 million, a make-whole premium of approximately $32.6 million and accrued and unpaid interest of approximately $1.0 million.
On February 17, 2018, we redeemed the approximately $49.4 million aggregate principal amount of the 2021 Senior Notes that remained outstanding after the Tender Offer and made a cash payment of approximately $52.7 million to the remaining holders of the 2021 Senior Notes, which included a make-whole premium of $3.0 million and accrued and unpaid interest of approximately $0.3 million. No 2021 Senior Notes remain outstanding.
2024 Senior Notes
In August 2017, we closed a private offering of our 2024 Senior Notes that resulted in net proceeds of approximately $392.6 million. Our 2024 Senior Notes bear interest at an annual rate of 7.375%. Interest on our 2024 Senior Notes is payable on May 15 and November 15 of each year, and the first interest payment was made on November 15, 2017. Our 2024 Senior Notes will mature on May 15, 2024.
We may, at our option, redeem all or a portion of our 2024 Senior Notes at any time on or after May 15, 2020 at the redemption prices set forth in the indenture governing the 2024 Senior Notes. We are also entitled to redeem up to 35% of the aggregate principal amount of our 2024 Senior Notes before May 15, 2020, with an amount of cash not greater than the net proceeds that we raise in certain equity offerings at a redemption price equal to 107.375% of the principal amount of our 2024 Senior Notes being redeemed plus accrued and unpaid interest, if any, to the redemption date. In addition, prior to May 15, 2020, we may redeem some or all of our 2024 Senior Notes at a price equal to 100% of the principal amount thereof, plus accrued and unpaid interest, if any, to the redemption date, plus a “make-whole” premium. If we experience certain kinds of changes of control, holders of our 2024 and 2026 Senior Notes may have the right to require us to repurchase their 2024 Senior Notesnotes at 101% of the principal amount of the 2024 Senior Notes,notes, plus accrued and unpaid interest, if any, to the date of purchase.
Our 2024 Senior Notes are our senior unsecured obligations and rank equally in right of payment with all of our other senior indebtedness and senior to any of our subordinated indebtedness. Our 2024 Senior Notes are fully and unconditionally guaranteed on a senior unsecured basis by each of our current subsidiaries and by certain future restricted subsidiaries that guarantee our indebtedness under a credit facility. The 2024 Senior Notes are effectively subordinated to all of our secured indebtedness (including all borrowings and other obligations under our revolving credit facility) to the extent of the value of the collateral securing such indebtedness, and structurally subordinated in right of payment to all existing and future indebtedness and other liabilities (including trade payables) of any of our future subsidiaries that do not guarantee the 2024 Senior Notes.Equity Arrangements
2026 Senior Notes
In January 2018, we closed a private offeringFor details of our 2026 Senior Notes that resulted in net proceeds of approximately $737.9 million. Our 2026 Senior Notes bear interest at an annual rate of 5.625%. Interest on the 2026 Senior Notes is payable on February 1 and August 1 of each year, and the first interest payment was made on August 1, 2018. Our 2026 Senior Notes will mature on February 1, 2026. As of November 8, 2019, we had repurchased 2026 Senior Notes with a nominal value of $49.8 million for $39.3 million in connection with the Senior Notes Repurchase Program.
We may, at our option, redeem all or a portion of our 2026 Senior Notes at any time on or after February 1, 2021 at the redemption prices set forth in the indenture governing the 2026 Senior Notes. We are also entitled to redeem up to 35% of the aggregate principal amount of our 2026 Senior Notes before February 1, 2021, with an amount of cash not greater than the net proceeds that we raise in certain equity offerings at a redemption price equal to 105.625% of the principal amount of our 2026 Senior Notes being redeemed plus accrued and unpaid interest, if any, to the redemption date. In addition, prior to February 1, 2021, we may redeem some or all of our 2026 Senior Notes at a price equal to 100% of the principal amount thereof, plus accrued and unpaid interest, if any, to the redemption date, plus a “make-whole” premium. If we experience certain kinds of changes of control, holders of our 2026 Senior Notes may have the right to require us to repurchase their 2026 Senior Notes at 101% of the principal amount of the 2026 Senior Notes, plus accrued and unpaid interest, if any, to the date of purchase.
Our 2026 Senior Notes are our senior unsecured obligations and rank equally in right of payment with all of our other senior indebtedness and senior to any of our subordinated indebtedness. Our 2026 Senior Notes are fully and unconditionally guaranteed on a senior unsecured basis by certain of our current subsidiaries and by certain future restricted subsidiaries that guarantee our indebtedness under a credit facility. The 2026 Senior Notes are effectively subordinated to all of our secured indebtedness (including all borrowings and other obligations under our revolving credit facility) to the extent of the value of the collateral securing such indebtedness, and structurally subordinated in right of payment to all existing and future indebtedness and other liabilities (including trade payables) of any of our future subsidiaries that do not guarantee the 2026 Senior Notes.
Series A Preferred Stock
The holders ofarrangements including our Series A Preferred Stock (the "Series A Preferred Stock") are entitled to receive a cash dividend of 5.875% per year, payable quarterly in arrears, and we have the ability to pay such quarterly dividends in kind at a dividend rate of 10% per year (decreased proportionately to the extent such quarterly dividends are partially paid in cash). The Series A Preferred Stock is convertible into shares of our common stock at the election of the Series A Preferred Holders at a conversion ratio per share of Series A Preferred Stock of 61.9195. Until the three-year anniversary of the closing of the IPO, we may elect to convert the Series A Preferred Stock at a conversion ratio per share of Series A Preferred Stock of 61.9195, but only if the closing price of our common stock trades at or above a certain premium to our initial offering price, such premium to decrease with time. On October 15, 2019, the three year anniversary had passed for the Series A Preferred Stock to convert into our common stock. We can now redeem the Series A Preferred Stock at any time for the liquidation preference, which is $185.3 million. In certain situations, including a change of control, the Series A Preferred Stock may be redeemed for cash in an amount equal to the greater of (i) 135% of the liquidation preference of the Series A Preferred Stock and (ii) a 17.5% annualized internal rate of return on the liquidation preference of the Series A Preferred Stock. The Series A Preferred Stock
matures on October 15, 2021, at which time they are mandatorily redeemable for cash at the liquidation preference. For more information, see the Company’s Annual Report.
Elevation Preferred Units
On July 3, 2018, Elevation entered into the Securities Purchase Agreement with the Purchaser, pursuant to which Elevation agreed to sell 150,000 Elevation Preferred Units, at a priceplease see Note 12—Equity in Part I, Item 1. Financial Information of $990 per Elevation Preferred Unit with an aggregate liquidation preference of $150.0 million, in a transaction exempt from the registration requirements under the Securities Act. The Private Placement closed on July 3, 2018 and resulted in net proceeds of approximately $141.9 million, $25.4 million of which was a reimbursement for previously incurred midstream capital expenditures and general and administrative expenses. These Elevation Preferred Units are non-recourse to Extraction, minimizing risk to our common shareholders, and represent the noncontrolling interest presented on the condensed consolidated statement of changes in stockholders' equity. Elevation is a separate entity and the assets and credit of Elevation are not available to satisfy the debts and other obligations of the Company or its other subsidiaries. As of September 30, 2019, $49.9 million of cash was held by Elevation and is earmarked for construction of pipeline infrastructure to serve the development of acreage in its Hawkeye and Southwest Wattenberg areas.
During the Commitment Period, subject to the satisfaction of certain financial and operational metrics and certain other customary closing conditions, Elevation has the right to require the Purchaser to purchase additional Elevation Preferred Units on the terms set forth in the Securities Purchase Agreement. Elevation may require the Purchaser to purchase additional Elevation Preferred Units, in increments of at least $25.0 million, up to an aggregate amount of $250.0 million. During the Commitment Period, Elevation is required to pay the Purchaser a quarterly commitment fee payable in cash or in kind of 1.0% per annum on any undrawn amounts of such additional $250.0 million commitment.
On July 10, 2019, Elevation closed on an additional 100,000 Elevation Preferred Units under an existing securities purchase agreement with a third party, pursuant to which Elevation had agreed to sell an additional 100,000 Elevation Preferred Units at a price of $990 per Elevation Preferred Unit with an aggregate liquidation preference of $100.0 million, and resulting in net proceeds of approximately $96.5 million, after deducting discounts and related offering expenses. These Elevation Preferred Units are non-recourse to Extraction. As part of the transaction, Extraction also committed to Elevation that it would drill at least 425 qualifying wells in the acreage dedicated to Elevation by December 31, 2023, subject to reductions if Extraction does not sell the full amount of additional Elevation Preferred Units to the Purchaser. By way of comparison, Extraction drilled a total of 90 gross wells during the nine months ended September 30, 2019.
The Elevation Preferred Units will entitle the Purchaser to receive quarterly dividends at a rate of 8.0% per annum. In respect of quarters ending prior to and including June 30, 2020, the Dividend is payable in cash or in kind at the election of Elevation. After June 30, 2020, the Dividend is payable solely in cash.
Critical Accounting Policies and Estimates
Effective June 14, 2020, as a result of the filing of the Chapter 11 Cases, we began accounting and reporting according to ASC 852—Reorganizations, which specifies the accounting and financial reporting requirements for entities reorganizing through chapter 11 bankruptcy proceedings. These requirements include distinguishing transactions associated with the reorganization separate from activities related to ongoing operations of the business.
There were no other material changes to our critical accounting policies and estimates from those disclosed in our Annual Report on Form 10-K for the year ended December 31, 2018.2019 other than the deconsolidation of Elevation Midstream, LLC discussed in Note 1—Business and Organization in Part I, Item 1. Financial Information of this Quarterly Report.
Recent Accounting Pronouncements
Please readsee Note 2—Basis of Presentation, Restatement, Significant Accounting Policies and Recent Accounting Pronouncements of the notes to the unaudited condensed consolidated financial statements included in Part 1, Item 1 of this Quarterly Report for a detailed list of recent accounting pronouncements.
Impact of Inflation/Deflation and Pricing
All of our transactions are denominated in U.S. dollars. Typically, as prices for oil and natural gas increase, associated costs rise. Conversely, as prices for oil and natural gas decrease, costs decline. Cost declines tend to lag and may not adjust downward in proportion to declinedeclining commodity prices. Historically, field-level prices received for our oil and natural gas production have been volatile. During the year ended December 31, 2018,2019, commodity prices increased during the first, second and third quarter, and subsequently decreased in the fourth quarter, while during the years ended December 31, 2017 and 2016, commodity prices generally increased.quarter. During the ninesix months ended SeptemberJune 30, 2019,2020, commodity prices decreased compared to the same period in 2018.2019. Changes in commodity prices impact our revenues, estimates of reserves, assessments of any impairment of oil and natural gas properties, as well as values of properties being acquired or sold. Price changes have the potential to affect our ability to raise capital, borrow money, and retain personnel.
Off-Balance Sheet Arrangements
As of SeptemberJune 30, 2019,2020, we did not have material off-balance sheet arrangements.
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURE ABOUT MARKET RISK
We are exposed to market risk, including the effects of adverse changes in commodity prices and interest rates as described below. The primary objective of the following information is to provide quantitative and qualitative information about our potential exposure to market risks. The term “market risk” refers to the risk of loss arising from adverse changes in oil, natural gas and NGL prices and interest rates. The disclosures are not meant to be precise indicators of expected future losses, but rather indicators of reasonably possible losses. All of our market risk sensitive instruments were entered into for purposes other than speculative trading. LIBOR is used as a reference rate for certain of our financial instruments, such as our revolving credit facility.Credit Facility. LIBOR is set to be phased out at the end of 2021. We are currently reviewing how the LIBOR phase-out will affect the Company, but we do not expect the impact to be material.
Commodity Price Risk
Our major market risk exposure is in the pricing that we receive for our oil, natural gas and NGL production. Pricing for oil, natural gas and NGL has been volatile and unpredictable for several years and this volatility is expected to continue in the future. The prices we receive for our oil, natural gas and NGL production depend on many factors outside of our control, such as the strength of the global economy and global supply and demand for the commodities we produce.
To reduce the impact of fluctuations in oil and natural gas prices on our revenues, we have periodically entered into commodity derivative contracts with respect to certain of our oil and natural gas production through various transactions that limit the downside of future prices received. We plan to continue our practice of entering into such transactions to reduce the impact of commodity price volatility on our cash flow from operations. Future transactions may include price swaps whereby we will receive a fixed price for our production and pay a variable market price to the contract counterparty. Additionally, we may enter into collars, whereby we receive the excess, if any, of the fixed floor over the floating rate or pay the excess, if any, of the floating rate over the fixed ceiling price. These hedging activities are intended to support oil and natural gas prices at targeted levels and to manage our exposure to oil price fluctuations.
For a summary of the Company’s commodity derivative contracts as of SeptemberJune 30, 2019,2020, please see Note 5—7—Commodity Derivative Instruments in Part 1, Item 1 of this Quarterly Report.
As of SeptemberJune 30, 2019,2020, the fair market value of our oil derivative contracts was a net asset of $95.2$52.7 million. Based on our open oil derivative positions at SeptemberJune 30, 2019,2020, a 10% increase in the NYMEX WTI price would decrease our net oil derivative asset by approximately $92.4$15.6 million, while a 10% decrease in the NYMEX WTI price would increase our net oil derivative asset by approximately $84.1$15.3 million. As of SeptemberJune 30, 2019,2020, the fair market value of our natural gas derivative contracts was a net asset of $12.6$2.9 million. Based upon our open commodity derivative positions at SeptemberJune 30, 2019,2020, a 10% increase in the NYMEX Henry Hub price would decrease our net natural gas derivative asset by approximately $7.6$0.8 million, while a 10% decrease in the NYMEX Henry Hub price would increase our net natural gas derivative asset by approximately $7.6$0.9 million. Please see “—How We Evaluate Our Operations—Derivative Arrangements.”
On June 14, 2020 we filed for relief under Chapter 11, which permitted the counterparties to our derivative instruments to terminate their outstanding hedges, and certain of our counterparties elected to exercise their right to terminate. Please refer to Note 7—Commodity Derivative Instruments in Part I, Item 1. Financial Information of this Quarterly Report for more information on these terminations, the effect such terminations will have on our cash flows, financial position and results of operations and other subsequent hedging activity.
Counterparty and Customer Credit Risk
Our cash and cash equivalents are exposed to concentrations of credit risk. We manage and control this risk by investing these funds with major financial institutions. We often have balances in excess of the federally insured limits.
We sell oil, natural gas and NGL to various types of customers, including pipelines and refineries. Credit is extended based on an evaluation of the customer’s financial conditions and historical payment record. The future availability of a ready market for oil, natural gas and NGL depends on numerous factors outside of our control, none of
which can be predicted with certainty. For the ninesix months ended SeptemberJune 30, 2019,2020, we had certain major customers that exceeded 10% of total oil, natural gas and NGL revenues. We do not believe the loss of any single purchaser would materially impact our operating results because oil, natural gas and NGL are fungible products with well-established markets and numerous purchasers.
At SeptemberJune 30, 2019,2020, we had commodity derivative contracts with ten counterparties.1 counterparty. We do not require collateral or other security from counterparties to support derivative instruments; however, to minimize the credit risk in derivative instruments, it is our policy to enter into derivative contracts only with counterparties that are creditworthy financial institutions deemed by management as competent and competitive market makers. Additionally, we use master netting agreements to minimize credit risk exposure. The creditworthiness of our counterparties is subject to periodic review. For the three and ninesix months ended SeptemberJune 30, 20192020 and 2018,2019, we did not incur any losses with respect to counterparty contracts. None of our existing derivative instrument contracts contain credit risk related contingent features.
Interest Rate Risk
At SeptemberJune 30, 2019,2020, we had $550.0$37.5 million variable-rate debt outstanding.outstanding related to our DIP Credit Facility. The impact on interest expense of a 1% increase or decrease in the average interest rate would be approximately $5.5$0.4 million per year. At June 30, 2020, we had $481.9 million variable-rate debt outstanding related to our Credit Facility. The impact on interest expense of a 1% increase or decrease in the average interest rate would be approximately $4.8 million per year. We may begin entering into interest rate swap arrangements on a portion of our outstanding debt to mitigate the risk of fluctuations in LIBOR if we have variable-rate debt outstanding in the future. Please see “—Liquidity and Capital Resources—Debt Arrangements.”
ITEM 4. CONTROLS AND PROCEDURES
Evaluation of Disclosure Controls and Procedures
Our management, with the participation of our principal executive officer and principal financial officer, evaluated the effectiveness of our disclosure controls and procedures to ensure that the information required to be disclosed by us in the reports that we file or submit under the Securities Exchange Act of 1934, as amended, is recorded, processed, summarized and reported within the time periods specified in the Securities and Exchange Commission’s rules and forms and to ensure that such information is accumulated and communicated to management, including our principal executive officer and principal financial officer, as appropriate to allow timely decisions regarding required disclosure.
At the time we filed Amendment No. 1 on Form 10-Q/A for the period ended September 30, 2019 on November 8, 2019, our principal executive officer and principal financial officer had concluded that as of September 30, 2019, the end of the period covered by this report, our disclosure controls and procedures were effective. Subsequent to Based upon that evaluation, our principal executive officer and principal financial officer have concluded that our disclosure controls and procedures were not effective as of SeptemberJune 30, 2019 because of a2020, due to the material weakness identified in our internal control over financial reporting. The Company is amending this Item 4 to reflect this conclusion.reporting as described below.
Management's Material Weakness Remediation Plan
A material weakness is a deficiency, or combination of deficiencies, in internal control over financial reporting, such that there is a reasonable possibility that a material misstatement of our annual or interim financial statements will not be prevented or detected on a timely basis. Management determined that the Company did not design and maintain effective controls to determine the appropriate contract termination date and evaluate the potential accounting implications of changes in termination dates of contracts with customers. This material weakness resulted in a restatement of the Company’s condensed consolidated financial statements as of and for the three and nine month periods ended September 30, 2019 and immaterial errors to the consolidated financial statements for the periods ended December 31, 2018, March 31, 2019 and June 30, 2019. The line items affected were oil sales, accounts payable and accrued liabilities, other non-current liabilities, inventory, prepaid expenses and other, and other non-current assets. Additionally, this material weakness could result in a misstatement of the interim or annual consolidatedaforementioned financial statementsstatement line items or disclosures that would result in a material misstatement to the annual or interim consolidated financial statements that would not be prevented or detected.
Plan for Remediation of Material Weakness
The Company and its Board of Directors are committed to maintaining a strong internal control environment. Management has evaluated the material weakness described above and is currently in the process of developingdeveloped a remediation plan to address the material weakness. The remediation plan is being implemented and includes further determination regardingadditional procedures around determining the contract termination date pursuant to the accounting treatment under ASC 606 - Revenue from Contracts with Customers.Customers. Management is
committed to successfully implementing the remediation plan and currently plans to commence the evaluation of its updated design of internal controls for implementation expeditiously.
Changes in Internal Control over Financial Reporting
There were no additional changes in our internal control over financial reporting during the three and six months ended SeptemberJune 30, 20192020 that materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
PART II—OTHER INFORMATION
ITEM 1. LEGAL PROCEEDINGS
Information regarding our legal proceedings can found in Note 11 – 14—Commitments and Contingencies -— Litigation and Legal Items to our condensed consolidated financial statements included elsewhereinPart I, Item 1. Financial Information in this report.Quarterly Report.
ITEM 1A. RISK FACTORS
Factors that could materially adversely affect our business, financial condition, operating results or liquidity and the trading price of our common stock are described under Item 1A “Risk Factors”, included in our Quarterly Report on Form 10-Q filed with the SEC on May 2, 2019below and under Item 1A "Risk Factors",Factors," included in our Annual Report on Form 10-K filed with the SEC on February 21, 2019.March 12, 2020 and the Quarterly Report on Form 10-Q filed with the SEC on May 11, 2020. The risks described below and in our annual and quarterly reports are not the only risks facing us. Additional risks and uncertainties not currently known to us or that we currently deem to be immaterial also may materially adversely affect our business, financial condition or future results. This information should be considered carefully, together with other information in this report and other reports and materials we file with the SEC.
We have restated prior financial statements, which may leadare subject to additionalthe risks and uncertainties including increased possibilityassociated with proceedings under chapter 11 of legal proceedingsthe Bankruptcy Code.
On June 14, 2020, Extraction and lossits wholly owned subsidiaries commenced voluntary cases under chapter 11 of investor confidence.the Bankruptcy Code and entered into the RSA. For the duration of our Chapter 11 Cases, our operations and our ability to develop and execute the business plan, as well as our continuation as a going concern, are subject to risks and uncertainties associated with bankruptcy. These risks include the following:
We have restated •our condensed consolidated financial statementsability to consummate a Restructuring Plan as of and forcontemplated by the three and nine months ended September 30, 2019 in order to correct certain accounting errors as described in Note 2—Basis of Presentation, Restatement, Significant Accounting Policies and Recent Accounting PronouncementsRSA with respect to the condensed consolidated financial statements (the “Restatement”). ForChapter 11 Cases;
•the high costs of bankruptcy proceedings and related fees;
•our ability to obtain sufficient financing to allow us to emerge from bankruptcy and execute our business plan post-emergence;
•our ability to maintain our relationships with our suppliers, service providers, customers, employees and other third parties;
•our ability to maintain contracts that are critical to our operations;
•our ability to execute our business plan in the current depressed commodity price environment;
•our ability to attract, motivate and retain key employees;
•the ability of third parties to seek and obtain court approval to terminate contracts and other agreements with us;
•the ability of third parties to seek and obtain court approval to convert the Chapter 11 Cases to a descriptionChapter 7 proceeding; and
•the actions and decisions of the material weaknessour creditors and other third parties who have interests in our internal control over financial reporting identified by managementChapter 11 Cases that may be inconsistent with our plans.
Delays in connectionour Chapter 11 Cases increase the risks of us being unable to reorganize our business and emerge from bankruptcy and increase our costs associated with the Restatement and management’s plan to remediate the material weakness, see “Part I, Item 4—Controls and Procedures.” As a result of the Restatement, we have become subject to possible additional costs for accounting and legal fees in connection with or related to the restatement and additionalbankruptcy process.
These risks and uncertainties including, among others,could affect our business and operations in various ways. For example, negative events or publicity associated with our Chapter 11 Cases could adversely affect our relationships with suppliers, service providers, customers, employees and other third parties, which in turn could adversely affect our operations and financial condition. Also, pursuant to the increased possibilityBankruptcy Code, we need the prior approval of legal proceedings, shareholder lawsuitsthe Bankruptcy Court for transactions outside the ordinary course of business, which may limit our ability to respond timely to certain events or take advantage of certain opportunities. We also need Bankruptcy Court confirmation of a reviewRestructuring Plan as contemplated by the SECRSA. Because of the risks and other regulatory bodies, which could cause investorsuncertainties associated with our Chapter 11 Cases, we cannot accurately predict or quantify the ultimate impact that events that occur during our Chapter 11 Cases will have on our business, financial condition, results of operations and cash flows.
Even if a Restructuring Plan is consummated, we will continue to loseface a number of risks, including our ability to reduce expenses, implement any strategic initiatives and generally maintain favorable relationships with and secure the confidence inof our reportedcounterparties. Accordingly, we cannot guarantee that the proposed financial information and could subject usrestructuring will achieve our stated goals nor can we give any assurance of our ability to civil or criminal penalties, shareholder class actions or derivative actions. We could face monetary judgments, penalties or other sanctions thatcontinue as a going concern.
Operating under the Bankruptcy Court protection for a long period of time may harm our business.
A long period of operations under the Bankruptcy Court protection could have a material adverse effect on our business, financial condition, and results of operations and could causeliquidity. A prolonged period of operating under Bankruptcy Court protection may also make it more difficult to retain management and other key personnel necessary to the success and growth of our stock pricebusiness. In addition, the longer the Chapter 11 Cases continue, the more likely it is that our customers and suppliers will lose confidence in our ability to decline.reorganize our business successfully and will seek to establish alternative commercial relationships. Furthermore, so long as the Chapter 11 Cases continue, we will be required to incur substantial costs for professional fees and other expenses associated with the administration of the Chapter 11 Cases.
Furthermore, we cannot predict the ultimate amount of all settlement terms for the liabilities that will be subject to the Restructuring Plan. Even once a Restructuring Plan is approved and implemented, our operating results may be adversely affected by the possible reluctance of prospective lenders and other counterparties to do business with a company that recently emerged from Chapter 11 bankruptcy.
We have identified a material weakness in our internal control over financial reporting that, ifmay not remediated, could result in additional material misstatements in our financial statements.be able to obtain confirmation of the Restructuring Plan.
As describedTo emerge successfully from Bankruptcy Court protection as a viable entity, we must meet certain statutory requirements with respect to adequacy of disclosure with respect to a Chapter 11 plan of reorganization, solicit and obtain the requisite acceptances of such a reorganization plan and fulfill other statutory conditions for confirmation of such a plan. However, even if the Restructuring Plan contemplated by the RSA meets other requirements under the Bankruptcy Code, certain parties in “Part I, Item 4—Controls and Procedures” and Note 2—Basis of Presentation, Restatement, Significant Accounting Policies and Recent Accounting Pronouncementsinterest may file objections to the condensed consolidated financial statements, management identified a control deficiencyplan in an effort to persuade the Bankruptcy Court that represents a material weakness. A material weakness is a deficiency, or a combinationwe have not satisfied the confirmation requirements under section 1129 of deficiencies, in internal control over financial reporting, such that there is a reasonable possibility that a material misstatementthe Bankruptcy Code. Even if no objections are filed and the requisite acceptances of our annualplan are received from creditors entitled to vote on the plan, the Bankruptcy Court, which can exercise substantial discretion, may not confirm the Restructuring Plan. The precise requirements and evidentiary showing for confirming a plan, notwithstanding its rejection by one or interim financial statements will not be preventedmore impaired classes of claims or detected onequity interests, depends upon a timely basis. As a resultnumber of factors including, without limitation, the status and seniority of the identified material weakness, management has concluded that we did not maintain effective internal control over financial reporting as of September 30, 2019.claims or equity interests in the rejecting class (i.e., secured claims or unsecured claims, subordinated or senior claims).
We are developing and implementing a remediation planIf no Restructuring Plan is confirmed by the Bankruptcy Court, it is unclear whether we would be able to address the material weakness. If our remediation efforts are insufficient or if additional material weaknesses in our internal control over financial reporting are discovered or occur in the future, our consolidated financial statements may contain material misstatements and we could be required to restate our financial results, which could materially and adversely affectreorganize our business resultsand what, if anything, holders of operations and financial condition, restrict our abilityclaims against us would ultimately receive with respect to access the capital markets, require us to expend significant resources to correct the material weakness, subject us to fines, penalties or judgments, harm our reputation or otherwise cause a decline in investor confidence.their claims.
We have substantial liquidity needs and may not be able to obtain sufficient liquidity for the duration of the Chapter 11 Cases or to confirm a plan of reorganization or liquidation.
Although we have lowered our capital budget and reduced the scale of our operations significantly, our business remains capital intensive. In addition to the cash requirements necessary to fund ongoing operations, we have incurred, and expect to continue to incur, significant professional fees and other costs in connection with the Chapter 11 Cases. As of June 30, 2020, our total available liquidity, consisting of cash on hand was $62.5 million. We expect to continue using additional cash that will further reduce this liquidity. As is described in Note 6—Long-Term Debt in Part I, Item 1. Financial Information in this Quarterly Report, on July 20, 2020, the Bankruptcy Court approved the Final DIP Order which increased the DIP Credit Facility's aggregate commitments to $125.0 million. In addition to a total of $90.0 million outstanding, we drew $20.0 million on July 27, 2020 leaving $15.0 million of availability on the facility. With the Bankruptcy Court’s approval of the Final DIP Order, we believe that we will have sufficient liquidity, including cash on hand and funds generated from ongoing operations, to fund anticipated cash requirements through the Chapter 11 Cases. As such, we expect to pay vendor and royalty obligations on a go-forward basis according to the terms of our current contracts and consistent with applicable court orders, if any, approving such payments. However, there can be no assurance that our current liquidity will be sufficient to allow us to satisfy our obligations related to the Chapter 11 Cases or to pursue confirmation of the Restructuring Plan. We can provide no assurance that we will be able to secure additional interim financing or exit financing sufficient to meet our liquidity needs or, if sufficient funds are available, offered to us on acceptable terms.
As a result of the Chapter 11 Cases, our financial results may be volatile and may not reflect historical trends.
During the Chapter 11 Cases, we expect our financial results to continue to be volatile as restructuring activities and expenses, contract terminations and rejections and claims assessments significantly impact our financial results. As a result, our historical financial performance is likely not indicative of financial performance after the date of the bankruptcy filing. In addition, if we emerge from Chapter 11, the amounts reported in subsequent periods may materially change relative to historical results, including due to revisions to our operating plans pursuant to the Restructuring Plan. We also may be required to adopt fresh start accounting, in which case our assets and liabilities will be recorded at fair value as of the fresh start reporting date, which may differ materially from the recorded values of assets and liabilities prior to seeking bankruptcy protection. Our financial results after the application of fresh start accounting also may be different from historical trends.
We may be subject to claims that will not be discharged in the Chapter 11 Cases, which could have a material adverse effect on our financial condition and results of operations.
The Bankruptcy Code provides that the confirmation of a plan of reorganization discharges a debtor from substantially all debts arising prior to confirmation. With few exceptions, all claims that arose before confirmation of the Restructuring Plan (i) would be subject to compromise and/or treatment under the Restructuring Plan and/or (ii) would be discharged in accordance with the terms of the Restructuring Plan. Any claims not ultimately discharged through the Restructuring Plan could be asserted against the reorganized entities and may have an adverse effect on their financial condition and results of operations on a post-reorganization basis.
The pursuit of the Chapter 11 Cases has consumed and will continue to consume a substantial portion of the time and attention of our management, which may have an adverse effect on our business and results of operations, and we may face increased levels of employee attrition.
While the Chapter 11 Cases continue, our management will be required to spend a significant amount of time and effort focusing on the Chapter 11 Cases instead of focusing exclusively on our business operations. This diversion of attention may materially adversely affect the conduct of our business, and, as a result, our financial condition and results of operations, particularly if the Chapter 11 Cases are protracted.
During the duration of the Chapter 11 Cases, our employees will face considerable distraction and uncertainty and we may experience increased levels of employee attrition. A loss of key personnel or material erosion of employee morale could have a material adverse effect on our ability to meet customer expectations, thereby adversely affecting our business and results of operations. The failure to retain or attract members of our management team and other key
personnel could impair our ability to execute our strategy and implement operational initiatives, thereby having a material adverse effect on our financial condition and results of operations.
In certain instances, a chapter 11 case may be converted to a case under chapter 7 of the Bankruptcy Code.
Upon a showing of cause, the Bankruptcy Court may convert our Chapter 11 Cases to cases under chapter 7 of the Bankruptcy Code. In such event, a chapter 7 trustee would be appointed or elected to liquidate our assets and the assets of our subsidiaries for distribution in accordance with the priorities established by the Bankruptcy Code. We believe that liquidation under chapter 7 would result in significantly smaller distributions being made to our creditors than those provided for in a plan of reorganization because of (i) the likelihood that the assets would have to be sold or otherwise disposed of in a distressed fashion over a short period of time rather than in a controlled manner and as a going concern, (ii) additional administrative expenses involved in the appointment of a chapter 7 trustee, and (iii) additional expenses and claims, some of which would be entitled to priority, that would be generated during the liquidation and from the rejection of leases and other executory contracts in connection with a cessation of operations.
Any plan of reorganization that we may implement will be based in large part upon assumptions and analyses developed by us. If these assumptions and analyses prove to be incorrect, our plan may be unsuccessful in its execution.
Any plan of reorganization that we may implement could affect both our capital structure and the ownership, structure and operation of our businesses and will reflect assumptions and analyses based on our experience and perception of historical trends, current conditions and expected future developments, as well as other factors that we consider appropriate under the circumstances. In addition, any plan of reorganization will rely upon financial projections, including with respect to revenues, capital expenditures, debt service and cash flow. Financial forecasts are necessarily speculative, and it is likely that one or more of the assumptions and estimates that are the basis of these financial forecasts will not be accurate. Whether actual future results and developments will be consistent with our expectations and assumptions depends on a number of factors, including but not limited to (i) our ability to substantially change our capital structure, (ii) our ability to obtain adequate liquidity and financing sources, (iii) our ability to maintain customers’ confidence in our viability as a continuing entity and to attract and retain sufficient business from them, (iv) our ability to retain key employees, and (v) the overall strength and stability of general economic conditions of the financial and oil and gas industries, both in the U.S. and in global markets. The failure of any of these factors could materially adversely affect the successful reorganization of our businesses. Consequently, there can be no assurance that the results or developments contemplated by any plan of reorganization we may implement will occur or, even if they do occur, that they will have the anticipated effects on us and our subsidiaries or our businesses or operations. The failure of any such results or developments to materialize as anticipated could materially adversely affect the successful execution of any plan of reorganization.
Even if the Restructuring Plan is consummated, we may not be able to achieve our stated goals and continue as a going concern.
Even if the Restructuring Plan is consummated, we will continue to face a number of risks, including further deterioration in commodity prices or other changes in economic conditions, changes in our industry, changes in market demand and increasing expenses. Accordingly, we cannot guarantee that the Restructuring Plan or any other chapter 11 plan of reorganization will achieve our stated goals.
Furthermore, even if our debts are reduced or discharged through such plan, we may need to raise additional funds through public or private debt or equity financing or other various means to fund our business after the completion of our Chapter 11 Cases. Our access to additional financing is, and for the foreseeable future will likely continue to be, extremely limited, if it is available at all. Therefore, adequate funds may not be available when needed or may not be available on favorable terms, if they are available at all.
Our ability to continue as a going concern is dependent upon our ability to raise additional capital. As a result, we cannot give any assurance of our ability to continue as a going concern, even if a chapter 11 plan of reorganization is confirmed.
Our ability to use our net operating loss carryforwards (“NOLs”) may be limited.
Transfers of our equity, or issuances of equity in connection with our Chapter 11 Cases, may impair our ability to utilize our federal income tax NOLs in future years. Under federal income tax law, a corporation is generally permitted to deduct from taxable income net operating losses carried forward from prior years. We have U.S. federal NOLs of approximately $1.1 billion as of December 31, 2019. Our ability to use our NOLs to offset future taxable income and to reduce federal income tax liability is subject to certain requirements and restrictions. If we experience an “ownership change,” as defined in section 382 of the Code, then our ability to use our NOLs may be substantially limited, which could have a negative impact on our financial position and results of operations. Generally, there is an “ownership change” if one or more shareholders owning 5% or more of a corporation’s stock have aggregate increases in their ownership of such stock of more than 50 percentage points over the prior three-year period. Following the implementation of a plan of reorganization, it is expected that an “ownership change” will be deemed to occur. Therefore, the amount of our net operating losses that may be used to offset future taxable income generally is expected to be subject to an annual limitation following our emergence from the Chapter 11 Cases, unless we are able to, and do not elect not to, utilize section 382(l)(5) of the Code.
Our common stock was delisted from the NASDAQ and is currently traded on the Pink Open Market, operated by OTC Markets Group Inc., which involves additional risks compared to being listed on a national securities exchange.
Trading in our common stock was suspended and removed from listing on NASDAQ on June 25, 2020. We will not be able to re-list our common stock on a national securities exchange during the pendency of the Chapter 11 Cases, although our common stock has been trading in the over-the-counter market. The trading of our common stock on the Pink Open Market rather than NASDAQ may negatively impact the trading price of our common stock and the levels of liquidity available to our stockholders. Securities traded on the Pink Open Market market generally have significantly less liquidity than securities traded on a national securities exchange due to factors such as the reduced number of investors that will consider investing in the securities, the reduced number of market makers in the securities, and the reduced number of securities analysts that follow such securities. As a result, holders of shares of our common stock may find it difficult to resell their shares at prices quoted in the market or at all. Furthermore, because of the limited market and generally low volume of trading in our common stock that could occur, the share price of our common stock could be more likely to be affected by broad market fluctuations, general market conditions, fluctuations in our operating results, changes in the markets perception of our business, and announcements made by us, our competitors, parties with whom we have business relationships or third parties with interests in the Chapter 11 Cases.
Because our common stock trades on the Pink Open Market, in some cases, we may be subject to additional compliance requirements under applicable state laws in the issuance of our securities. The lack of liquidity in our common stock may also make it difficult for us to issue additional securities for financing or other purposes, or to otherwise arrange for any financing we may need in the future. Accordingly, we urge that extreme caution be exercised with respect to existing and future investments in our common stock.
As of July 27, 2020, we have only $15.0 million of availability under our DIP Credit Facility. Unless we are able to successfully discharge or restructure our existing indebtedness, obtain further waivers or forbearance from our existing lenders or otherwise raise significant capital, it is unlikely that we will be able to meet our obligations as they become due, and we may not be able to continue as a going concern.
Our working capital deficit was $322.1 million and $240.8 million at June 30, 2020 and December 31, 2019, respectively. However, as of June 30, 2020, many of our current liabilities were classified as liabilities subject to compromise. Our cash balances totaled $62.6 million and $32.4 million at June 30, 2020 and December 31, 2019, respectively. For the year ended December 31, 2019, the Company incurred net losses of approximately $1.4 billion. Our continuation as a going concern is dependent upon attaining and maintaining profitable operations and, until that time, raising additional capital as needed, but there can be no assurance that we will be able to obtain sufficient financing. Our ability to generate positive cash flow from operations is dependent upon generating sufficient revenues. To date, our operations have been funded by the sale of oil, gas and NGL production based on prevailing market prices, which decreased significantly in March and April 2020. Our operations have also been funded through availability on our DIP Credit Facility and previously, our Credit Facility. As is described in Note 6—Long-Term Debt in Part I, Item 1. Financial Information in this Quarterly Report, on July 20, 2020, the Bankruptcy Court approved the Final DIP Order
which increased the DIP Credit Facility's aggregate commitments to $125.0 million. In addition to a total of $90.0 million outstanding, we drew $20.0 million on July 27, 2020 leaving $15.0 million of availability on the facility. With the Bankruptcy Court’s approval of the Final DIP Order, we believe that we will have sufficient liquidity, including cash on hand and funds generated from ongoing operations, to fund anticipated cash requirements through the Chapter 11 Cases. As such, we expect to pay vendor and royalty obligations on a go-forward basis according to the terms of our current contracts and consistent with applicable court orders, if any, approving such payments. However, there can be no assurance that our current liquidity will be sufficient to allow us to satisfy our obligations related to the Chapter 11 Cases or to pursue confirmation of the Restructuring Plan and thus continue as a going concern. We can provide no assurance that we will be able to secure additional interim financing or exit financing sufficient to meet our liquidity needs to continue as a going concern.
Outbreaks of communicable diseases, including the COVID-19 pandemic, could adversely affect our business, financial condition, results of operations and cash flows.
Global or national health concerns, including the outbreak of pandemic or contagious disease, can negatively impact the global economy and, therefore, demand and pricing for oil and natural gas products. For example, there have been recent outbreaks in many countries, including the United States, of a highly transmissible and pathogenic coronavirus, which the World Health Organization declared a pandemic in March 2020. The outbreak of communicable diseases, or the perception that such an outbreak could occur, could result in a widespread public health crisis that could adversely affect the economies and financial markets of many countries, resulting in an economic downturn that would negatively impact the demand for oil and natural gas products. Furthermore, uncertainty regarding the impact and length of any outbreak of pandemic or contagious disease, including COVID-19, could lead to increased volatility in oil and natural gas prices. The occurrence or continuation of any of these events could lead to decreased revenues and limit our ability to execute on our business plan, which could adversely affect our business, financial condition, results of operations and cash flows.
Additionally, in response to the COVID-19 pandemic, our corporate staff has begun working remotely and many of our key vendors, service suppliers and partners have similarly begun to work remotely. As a result of such remote work arrangements, certain operational, reporting, accounting and other processes may slow, which could result in longer time to execute critical business functions, higher operating costs and uncertainties regarding the quality of services and supplies. Also, in the event that there is an outbreak of COVID-19 at any of our operating locations, we could be forced to cease operations at such location. Any of the foregoing could adversely affect our business, financial condition, results of operations and cash flows.
ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS
The following table sets forth our share repurchase activity for the period presented:
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| Period | | Total Number of Shares Purchased | | Average Price Paid per Share | | Total Number of Shares Purchased as Part of Publicly Announced Plans or Program | | Approximate Dollar Value of Shares that May Yet be Purchased under the Plans or Programs (in millions) (1) |
| July 1, 2019 - July 31, 2019 | | 4,807,150 | | | $ | 4.42 | | | 4,807,150 | | | $ | — | |
(1)On April 1, 2019, we announced an extension of our ongoing repurchase program until December 31, 2019 and an increase of the program to authorize repurchases up to an incremental amount of $100.0 million in common stock from the date of the extension, bringing the total amount authorized to be repurchased to approximately $163.2 million. The July 2019 share repurchase completed the authorized Share Repurchase Program.
ITEM 3. DEFAULTS UPON SENIOR SECURITIES
None.The commencement of a voluntary proceeding in bankruptcy constituted an immediate event of default under the Credit Agreement and the indentures governing the Company’s Senior Notes, resulting in the automatic and immediate acceleration of all of the Company’s debt outstanding under the Credit Agreement and Senior Notes. Accordingly, the Company has classified its outstanding senior note debt as liabilities subject to compromise on its condensed consolidated balance sheet as of June 30, 2020. The Credit Facility was not classified as liabilities subject to compromise because it is fully secured in the Chapter 11 Cases and is expected to be unimpaired. Please refer to Note 4—Liabilities Subject to Compromise and Note 6—Long-Term Debt in Part I, Item 1. Financial Information in this Quarterly Report.
ITEM 4. MINE SAFETY DISCLOSURES
Not applicable.
ITEM 5. OTHER INFORMATION
None.
ITEM 6. EXHIBITS
(a) Exhibits:
The exhibits listed on the accompanying Exhibit Index are filed, furnished or incorporated by reference as part of this report, and such Exhibit Index is incorporated herein by reference.
INDEX TO EXHIBITS
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Exhibit
Number | | Description | |
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| | Master Assignment and Amendment No. 8 to Amended and Restated CreditRestructuring Support Agreement dated as of August 28, 2019, by and among Extraction Oil & Gas, Inc.June 14, as borrower, certain of its subsidiaries, as guarantors, the lenders party thereto, and Wells Fargo Bank, National Association, as administrative agent and issuing lender2020 (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K (File No. 001-37907) filed with the Commission on August 30, 2019)June 14, 2020). | |
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| | Superpriority Senior Secured Debtor-in-Possession Credit Agreement, dated as of June 16, 2020, by and among Extraction Oil & Gas, Inc., XOG Services, LLC.the subsidiary guarantors party thereto, the lenders party thereto and Russell T. Kelley, Jr.Wells Fargo Bank, National Association (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K (File No. 001-37907) filed with the Commission on September 4, 2019)July 24, 2020). | |
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| | Borrowing Base Decrease Agreement, dated as of November 4, 2019, among Extraction Oil & Gas, Inc., as borrower, certain subsidiaries of Extraction Oil & Gas, Inc., as guarantors, the lenders party thereto and Wells Fargo Bank, National Association, as administrative agent (incorporated by reference to Exhibit 10.1 to the Company's Current Report on Form 8-K (File No. 001-37907) filed with the Commission on November 7, 2019). |
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| *101 | | Interactive Data Files | |
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| † | | Management contract or compensatory plan or agreement. | |
| * | | Filed herewith. | |
| ** | | Furnished herewith. | |
* Filed herewith.
** Furnished herewith.
† Management contract or compensatory plan or agreement.
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
Date: December 23, 2019.August 10, 2020.
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| Extraction Oil & Gas, Inc. | |
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| By: | /S/ MATTHEW R. OWENS |
| | Matthew R. Owens |
| | President and Acting Chief Executive Officer (principal executive officer) |
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| By: | /S/ TOM L. BROCK.BROCK |
| | Tom L. Brock |
| | Vice President and Chief Accounting Officer (principal financial officer) |
