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As Of Filer Filing For·On·As Docs:Size Issuer Filing Agent 8/08/22 Battalion Oil Corp. 10-Q 6/30/22 66:7.3M Toppan Merrill Bridge/FA |
Document/Exhibit Description Pages Size
1: 10-Q Quarterly Report HTML 1.81M
2: EX-31.1 Certification -- §302 - SOA'02 HTML 24K
3: EX-31.2 Certification -- §302 - SOA'02 HTML 24K
4: EX-32 Certification -- §906 - SOA'02 HTML 21K
10: R1 Document and Entity Information HTML 72K
11: R2 Consolidated Statements of Operations HTML 110K
12: R3 Consolidated Balance Sheets HTML 134K
13: R4 Consolidated Balance Sheets (Parenthetical) HTML 26K
14: R5 Consolidated Statements of Stockholders' Equity HTML 69K
15: R6 Consolidated Statements of Cash Flows HTML 97K
16: R7 Financial Statement Presentation HTML 43K
17: R8 Leases HTML 65K
18: R9 Operating Revenues HTML 25K
19: R10 Oil and Natural Gas Properties HTML 24K
20: R11 Debt HTML 63K
21: R12 Fair Value Measurements HTML 80K
22: R13 Derivative and Hedging Activities HTML 186K
23: R14 Asset Retirement Obligations HTML 27K
24: R15 Commitments and Contingencies HTML 24K
25: R16 Stockholders' Equity HTML 25K
26: R17 Earnings Per Share HTML 81K
27: R18 Additional Financial Statement Information HTML 68K
28: R19 Financial Statement Presentation (Policies) HTML 56K
29: R20 Financial Statement Presentation (Tables) HTML 30K
30: R21 Leases (Tables) HTML 64K
31: R22 Debt (Tables) HTML 48K
32: R23 Fair Value Measurements (Tables) HTML 76K
33: R24 Derivative and Hedging Activities (Tables) HTML 188K
34: R25 Asset Retirement Obligations (Tables) HTML 26K
35: R26 Earnings Per Share (Tables) HTML 79K
36: R27 Additional Financial Statement Information HTML 68K
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40: R31 Leases - Reported under ASC 842 and ASC 840 HTML 32K
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41: R32 OPERATING REVENUES - Revenue Recognition (Details) HTML 46K
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43: R34 Debt (Details) HTML 40K
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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM i 10-Q
| |
i ☒ | QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15 (d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the quarterly period ended i June 30, 2022 | |
OR | |
i ☐ | 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: i 001-35467
i i Battalion Oil Corp / oration
(Exact name of registrant as specified in its charter)
i Delaware | 1311 | i 20-0700684 |
i 3505 West Sam Houston Parkway North, i Suite 300, i Houston, i TX i 77043
(Address of principal executive offices)
( i 832) i 538-0300
(Registrant’s telephone number, including area code)
(Former name, former address and former fiscal year, if changed since last report)
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. i 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). i 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 filer ◻ | Accelerated filer ◻ | i Non-accelerated filer ⌧ | Smaller reporting company i ☒ Emerging growth company i ☐ |
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 Act). Yes i ☐ No ⌧
Securities registered pursuant to Section 12(b) of the Act:
| | | | |
Title of each class | | Trading Symbol | | Name of each exchange on which registered |
i Common Stock, par value $0.0001 | | i BATL | | i NYSE American |
Indicate by check mark whether the registrant has filed all documents and reports required to be filed by Section 12, 13 or 15(d) of the Securities Exchange Act of 1934 subsequent to the distribution of securities made under a plan confirmed by a court. Yes ⌧ No ◻
At August 4, 2022, i 16,337,910 shares of the Registrant’s Common Stock were outstanding.
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| | Condensed Consolidated Balance Sheets (Unaudited) as of June 30, 2022 and December 31, 2021 | | 6 |
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| | Notes to Unaudited Condensed Consolidated Financial Statements | | 10 |
| Management’s Discussion and Analysis of Financial Condition and Results of Operations | | 26 | |
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2
Special note regarding forward-looking statements
This Quarterly Report on Form 10-Q contains forward-looking statements within the meaning of the federal securities laws. All statements, other than statements of historical facts, are forward looking statements and may concern, among other things, planned capital expenditures, potential increases in oil and natural gas production, potential costs to be incurred, future cash flows and borrowings, our financial position, business strategy and other plans and objectives for future operations. These forward-looking statements may be identified by their use of terms and phrases such as “may,” “expect,” “estimate,” “project,” “plan,” “objective,” “believe,” “predict,” “intend,” “achievable,” “anticipate,” “will,” “continue,” “potential,” “should,” “could” and similar terms and phrases. Although we believe that the expectations reflected in forward-looking statements are reasonable, they do involve certain assumptions, risks and uncertainties. Actual results could differ materially from those anticipated in these forward-looking statements. Readers should consider carefully the risks described under the “Risk Factors” section of our previously filed Annual Report on Form 10-K for the fiscal year ended December 31, 2021, as well as the other disclosures contained herein and therein, which describe factors that could cause our actual results to differ from those anticipated in forward-looking statements, which include, but are not limited to, the following factors:
| ● | volatility in commodity prices for oil, natural gas and natural gas liquids; |
| ● | our ability to generate sufficient cash flow from operations, borrowings or other sources to enable us to fund our operations, satisfy our obligations and develop our undeveloped acreage positions; |
| ● | impacts and potential risks related to actual or anticipated pandemics, such as the novel coronavirus (COVID-19) pandemic, including how it has and may continue to impact our operations, financial results, liquidity, contractors, customers, employees and vendors; |
| ● | our indebtedness, which may increase in the future, and higher levels of indebtedness can make us more vulnerable to economic downturns and adverse developments in our business; |
| ● | our ability to replace our oil and natural gas reserves and production; |
| ● | the presence or recoverability of estimated oil and natural gas reserves attributable to our properties and the actual future production rates and associated costs of producing those oil and natural gas reserves; |
| ● | our ability to successfully develop our large inventory of undeveloped acreage; |
| ● | our ability to secure adequate sour gas treating and/or sour gas take-away capacity in our Monument Draw area sufficient to handle production volumes; |
| ● | drilling and operating risks, including accidents, equipment failures, fires, and leaks of toxic or hazardous materials, such as H2S, which can result in injury, loss of life, pollution, property damage and suspension of operations; |
| ● | the cost and availability of goods and services, such as drilling rigs, fracture stimulation services and tubulars; |
| ● | our ability to retain key members of senior management, the board of directors and key technical employees; |
| ● | senior management’s ability to execute our plans to meet our goals; |
| ● | access to and availability of water, sand and other treatment materials to carry out fracture stimulations in our completion operations; |
| ● | the possibility that our industry may be subject to future regulatory or legislative actions (including additional taxes and changes in environmental regulations); |
| ● | access to adequate gathering systems, processing and treating facilities and transportation take-away capacity to move our production to marketing outlets to sell our production at market prices; |
| ● | contractual limitations that affect our management’s discretion in managing our business, including covenants that, among other things, limit our ability to incur debt, make investments and pay cash dividends; |
| ● | the potential for production decline rates for our wells to be greater than we expect; |
| ● | competition, including competition for acreage in our resource play; |
| ● | environmental risks, such as accidental spills of toxic or hazardous materials, and the potential for environmental liabilities; |
| ● | exploration and development risks; |
| ● | social unrest, political instability or armed conflict in major oil and natural gas producing regions outside the United States, such as the conflict between Ukraine and Russia, and acts of terrorism or sabotage; |
| ● | general economic conditions, whether internationally, nationally or in the regional and local market areas in which we do business, may be less favorable than expected, including the possibility that economic conditions |
3
| in the United States will worsen and that capital markets are disrupted, which could adversely affect demand for oil and natural gas and make it difficult to access capital; |
| ● | other economic, competitive, governmental, regulatory, legislative, including federal and state regulations and laws, geopolitical and technological factors that may negatively impact our business, operations or oil and natural gas prices; |
| ● | our insurance coverage may not adequately cover all losses that we may sustain; and |
| ● | title to the properties in which we have an interest may be impaired by title defects. |
All forward-looking statements are expressly qualified in their entirety by the cautionary statements in this paragraph and elsewhere in this document. Other than as required under the securities laws, 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.
4
PART I. FINANCIAL INFORMATION
Item 1. Condensed Consolidated Financial Statements (Unaudited)
BATTALION OIL CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS (Unaudited)
(In thousands, except per share amounts)
| | | | | | | | | | | | |
| | Three Months Ended | | Six Months Ended | ||||||||
| | June 30, | | |||||||||
| | 2022 | | 2021 | | 2022 | | 2021 | ||||
Operating revenues: | | | | | | | | | | | | |
Oil, natural gas and natural gas liquids sales: | | | | | | | | | | | | |
Oil | | $ | i 73,944 | | $ | i 51,935 | | $ | i 136,468 | | $ | i 93,205 |
Natural gas | | | i 14,759 | | | i 5,317 | | | i 23,640 | | | i 14,404 |
Natural gas liquids | | | i 12,587 | | | i 6,851 | | | i 22,590 | | | i 11,760 |
Total oil, natural gas and natural gas liquids sales | | | i 101,290 | | | i 64,103 | | | i 182,698 | | | i 119,369 |
Other | | | i 221 | | | i 263 | | | i 415 | | | i 515 |
Total operating revenues | | | i 101,511 | | | i 64,366 | | | i 183,113 | | | i 119,884 |
| | | | | | | | | | | | |
Operating expenses: | | | | | | | | | | | | |
Production: | | | | | | | | | | | | |
Lease operating | | | i 11,909 | | | i 10,169 | | | i 23,433 | | | i 19,636 |
Workover and other | | | i 1,383 | | | i 767 | | | i 2,248 | | | i 1,327 |
Taxes other than income | | | i 5,372 | | | i 2,912 | | | i 10,323 | | | i 6,104 |
Gathering and other | | | i 15,869 | | | i 14,331 | | | i 31,124 | | | i 27,502 |
General and administrative | | | i 4,588 | | | i 4,031 | | | i 9,573 | | | i 8,858 |
Depletion, depreciation and accretion | | | i 12,601 | | | i 11,249 | | | i 22,821 | | | i 21,844 |
Total operating expenses | | | i 51,722 | | | i 43,459 | | | i 99,522 | | | i 85,271 |
Income (loss) from operations | | | i 49,789 | | | i 20,907 | | | i 83,591 | | | i 34,613 |
| | | | | | | | | | | | |
Other income (expenses): | | | | | | | | | | | | |
Net gain (loss) on derivative contracts | | | ( i 31,910) | | | ( i 53,089) | | | ( i 155,768) | | | ( i 98,800) |
Interest expense and other | | | ( i 4,832) | | | ( i 1,747) | | | ( i 7,520) | | | ( i 3,117) |
Total other income (expenses) | | | ( i 36,742) | | | ( i 54,836) | | | ( i 163,288) | | | ( i 101,917) |
Income (loss) before income taxes | | | i 13,047 | | | ( i 33,929) | | | ( i 79,697) | | | ( i 67,304) |
Income tax benefit (provision) | | | — | | | — | | | — | | | — |
Net income (loss) | | $ | i 13,047 | | $ | ( i 33,929) | | $ | ( i 79,697) | | $ | ( i 67,304) |
| | | | | | | | | | | | |
Net income (loss) per share of common stock: | | | | | | | | | | | | |
Basic | | $ | i 0.80 | | $ | ( i 2.09) | | $ | ( i 4.88) | | $ | ( i 4.14) |
Diluted | | $ | i 0.79 | | $ | ( i 2.09) | | $ | ( i 4.88) | | $ | ( i 4.14) |
Weighted average common shares outstanding: | | | | | | | | | | | | |
Basic | | | i 16,338 | | | i 16,268 | | | i 16,320 | | | i 16,250 |
Diluted | | | i 16,510 | | | i 16,268 | | | i 16,320 | | | i 16,250 |
The accompanying notes are an integral part of these unaudited condensed consolidated financial statements.
5
BATTALION OIL CORPORATION
CONDENSED CONSOLIDATED BALANCE SHEETS (Unaudited)
(In thousands, except share and per share amounts)
| | | | | | |
| | | ||||
Current assets: | | | | | | |
Cash and cash equivalents | | $ | i 43,640 | | $ | i 46,864 |
Accounts receivable, net | | | i 53,002 | | | i 36,806 |
Assets from derivative contracts | | | i 6,146 | | | i 1,383 |
Restricted cash | | | i 135 | | | i 1,495 |
Prepaids and other | | | i 927 | | | i 1,366 |
Total current assets | | | i 103,850 | | | i 87,914 |
Oil and natural gas properties (full cost method): | | | | | | |
Evaluated | | | i 632,004 | | | i 569,886 |
Unevaluated | | | i 64,760 | | | i 64,305 |
Gross oil and natural gas properties | | | i 696,764 | | | i 634,191 |
Less - accumulated depletion | | | ( i 362,257) | | | ( i 339,776) |
Net oil and natural gas properties | | | i 334,507 | | | i 294,415 |
Other operating property and equipment: | | | | | | |
Other operating property and equipment | | | i 4,045 | | | i 3,467 |
Less - accumulated depreciation | | | ( i 1,027) | | | ( i 1,035) |
Net other operating property and equipment | | | i 3,018 | | | i 2,432 |
Other noncurrent assets: | | | | | | |
Assets from derivative contracts | | | i 3,972 | | | i 2,515 |
Operating lease right of use assets | | | i 539 | | | i 721 |
Other assets | | | i 3,329 | | | i 2,270 |
Total assets | | $ | i 449,215 | | $ | i 390,267 |
| | | | | | |
Current liabilities: | | | | | | |
Accounts payable and accrued liabilities | | $ | i 97,334 | | $ | i 62,826 |
Liabilities from derivative contracts | | | i 91,750 | | | i 58,322 |
Current portion of long-term debt | | | i 15,000 | | | i 85 |
Operating lease liabilities | | | i 377 | | | i 369 |
Asset retirement obligations | | | i 401 | | | — |
Total current liabilities | | | i 204,862 | | | i 121,602 |
Long-term debt, net | | | i 188,372 | | | i 181,565 |
Other noncurrent liabilities: | | | | | | |
Liabilities from derivative contracts | | | i 58,138 | | | i 7,144 |
Asset retirement obligations | | | i 11,686 | | | i 11,896 |
Operating lease liabilities | | | i 162 | | | i 352 |
Other | | | i 1,408 | | | i 4,003 |
Commitments and contingencies (Note 9) | | | | | | |
| | | | | | |
Stockholders' equity: | | | | | | |
Common stock: i i 100,000,000 / shares of $ i i 0.0001 / par value authorized; | | | | | | |
i 16,337,910 and i 16,273,913 shares issued and outstanding as of | | | | | | |
June 30, 2022 and December 31, 2021, respectively | | | i 2 | | | i 2 |
Additional paid-in capital | | | i 332,766 | | | i 332,187 |
Retained earnings (accumulated deficit) | | | ( i 348,181) | | | ( i 268,484) |
Total stockholders' equity | | | ( i 15,413) | | | i 63,705 |
Total liabilities and stockholders' equity | | $ | i 449,215 | | $ | i 390,267 |
The accompanying notes are an integral part of these unaudited condensed consolidated financial statements.
6
BATTALION OIL CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY (Unaudited)
(In thousands)
| | | | | | | | | | | | | | |
| | | | | | | | | | Retained | | | | |
| | | | | | | Additional | | Earnings | | | | ||
| | Common Stock | | Paid-In | | (Accumulated | | Stockholders' | ||||||
|
| Shares |
| Amount |
| Capital |
| Deficit) |
| Equity | ||||
Balances at December 31, 2021 | | i 16,274 | | $ | i 2 | | $ | i 332,187 | | $ | ( i 268,484) | | $ | i 63,705 |
Net income (loss) | | — | | | — | | | — | | | ( i 92,744) | | | ( i 92,744) |
Long-term incentive plan vestings | | i 89 | | | — | | | — | | | — | | | — |
Reduction in shares to cover | | | | | | | | | | | | | | |
individuals' tax withholding | | ( i 26) | | | — | | | ( i 461) | | | — | | | ( i 461) |
Stock-based compensation | | — | | | — | | | i 452 | | | — | | | i 452 |
Balances at March 31, 2022 | | i 16,337 | | | i 2 | | | i 332,178 | | | ( i 361,228) | | | ( i 29,048) |
Net income (loss) | | — | | | — | | | — | | | i 13,047 | | | i 13,047 |
Long-term incentive plan vestings | | i 1 | | | — | | | — | | | — | | | — |
Reduction in shares to cover | | | | | | | | | | | | | | |
individuals' tax withholding | | — | | | — | | | ( i 6) | | | — | | | ( i 6) |
Stock-based compensation | | — | | | — | | | i 594 | | | — | | | i 594 |
Balances at June 30, 2022 | | i 16,338 | | | i 2 | | | i 332,766 | | | ( i 348,181) | | | ( i 15,413) |
The accompanying notes are an integral part of these unaudited condensed consolidated financial statements
7
BATTALION OIL CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY (Unaudited)
(In thousands)
| | | | | | | | | | | | | | |
| | | | | | | | | | Retained | | | | |
| | | | | | | Additional | | Earnings | | | | ||
| | Common Stock | | Paid-In | | (Accumulated | | Stockholders' | ||||||
|
| Shares |
| Amount |
| Capital |
| Deficit) |
| Equity | ||||
Balances at December 31, 2020 | | i 16,204 | | $ | i 2 | | $ | i 330,123 | | $ | ( i 240,167) | | $ | i 89,958 |
Net income (loss) | | — | | | — | | | — | | | ( i 33,375) | | | ( i 33,375) |
Long-term incentive plan vestings | | i 87 | | | — | | | — | | | — | | | — |
Reduction in shares to cover | | | | | | | | | | | | | | |
individuals' tax withholding | | ( i 24) | | | — | | | ( i 264) | | | — | | | ( i 264) |
Stock-based compensation | | — | | | — | | | i 692 | | | — | | | i 692 |
Balances at March 31, 2021 | | i 16,267 | | | i 2 | | | i 330,551 | | | ( i 273,542) | | | i 57,011 |
Net income (loss) | | — | | | — | | | — | | | ( i 33,929) | | | ( i 33,929) |
Long-term incentive plan vestings | | i 1 | | | — | | | — | | | — | | | — |
Reduction in shares to cover | | | | | | | | | | | | | | |
individuals' tax withholding | | — | | | — | | | ( i 5) | | | — | | | ( i 5) |
Stock-based compensation | | — | | | — | | | i 571 | | | — | | | i 571 |
Balances at June 30, 2021 | | i 16,268 | | | i 2 | | | i 331,117 | | | ( i 307,471) | | | i 23,648 |
Net income (loss) | | — | | | — | | | — | | | i 13,052 | | | i 13,052 |
Long-term incentive plan vestings | | i 8 | | | — | | | — | | | — | | | — |
Reduction in shares to cover | | | | | | | | | | | | | | |
individuals' tax withholding | | ( i 2) | | | — | | | ( i 22) | | | — | | | ( i 22) |
Stock-based compensation | | — | | | — | | | i 565 | | | — | | | i 565 |
Balances at September 30, 2021 | | i 16,274 | | | i 2 | | | i 331,660 | | | ( i 294,419) | | | i 37,243 |
Net income (loss) | | — | | | — | | | — | | | i 25,935 | | | i 25,935 |
Stock-based compensation | | — | | | — | | | i 527 | | | — | | | i 527 |
Balances at December 31, 2021 | | i 16,274 | | $ | i 2 | | $ | i 332,187 | | $ | ( i 268,484) | | $ | i 63,705 |
The accompanying notes are an integral part of these unaudited condensed consolidated financial statements.
8
BATTALION OIL CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited)
(In thousands)
| | | | | | |
| Six Months Ended | |||||
| ||||||
| 2022 | | 2021 | |||
Cash flows from operating activities: | | | | | | |
Net income (loss) | | $ | ( i 79,697) | | $ | ( i 67,304) |
Adjustments to reconcile net income (loss) to net cash | | | | | | |
provided by (used in) operating activities: | | | | | | |
Depletion, depreciation and accretion | | | i 22,821 | | | i 21,844 |
Stock-based compensation, net | | | i 857 | | | i 1,079 |
Unrealized loss (gain) on derivative contracts | | | i 78,201 | | | i 70,869 |
Amortization of deferred loan costs | | | i 1,807 | | | — |
(Gain) loss on sale of other assets | | | ( i 96) | | | — |
Reorganization items | | | ( i 744) | | | — |
Accrued settlements on derivative contracts | | | i 14,652 | | | i 6,972 |
Change in fair value of Change of Control Call Option | | | ( i 2,595) | | | — |
Other income (expense) | | | — | | | ( i 287) |
Change in assets and liabilities: | | | | | | |
Accounts receivable | | | ( i 12,596) | | | ( i 5,488) |
Prepaids and other | | | i 438 | | | ( i 441) |
Accounts payable and accrued liabilities | | | i 5,285 | | | i 1,856 |
Net cash provided by (used in) operating activities | | | i 28,333 | | | i 29,100 |
| | | | | | |
Cash flows from investing activities: | | | | | | |
Oil and natural gas capital expenditures | | | ( i 51,377) | | | ( i 37,593) |
Proceeds received from sale of oil and natural gas properties | | | — | | | i 926 |
Other operating property and equipment capital expenditures | | | ( i 705) | | | — |
Proceeds received from sale of other operating property and equipment | | | i 96 | | | — |
Funds held in escrow and other | | | — | | | ( i 2) |
Net cash provided by (used in) investing activities | | | ( i 51,986) | | | ( i 36,669) |
| | | | | | |
Cash flows from financing activities: | | | | | | |
Proceeds from borrowings | | | i 20,000 | | | i 82,000 |
Repayments of borrowings | | | ( i 85) | | | ( i 77,000) |
Debt issuance costs | | | ( i 379) | | | — |
Other | | | ( i 467) | | | ( i 268) |
Net cash provided by (used in) financing activities | | | i 19,069 | | | i 4,732 |
| | | | | | |
Net increase (decrease) in cash, cash equivalents and restricted cash | | | ( i 4,584) | | | ( i 2,837) |
| | | | | | |
Cash, cash equivalents and restricted cash at beginning of period | | | i 48,359 | | | i 4,295 |
Cash, cash equivalents and restricted cash at end of period | | $ | i 43,775 | | $ | i 1,458 |
| | | | | | |
| | | | | | |
Supplemental cash flow information: | | | | | | |
Cash paid for reorganization items | | $ | i 744 | | $ | — |
| | | | | | |
The accompanying notes are an integral part of these unaudited condensed consolidated financial statements.
9
BATTALION OIL CORPORATION
NOTES TO THE UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
1. FINANCIAL STATEMENT PRESENTATION
iBasis of Presentation and Principles of Consolidation
Battalion is an independent energy company focused on the acquisition, production, exploration and development of onshore liquids-rich oil and natural gas assets in the United States. The consolidated financial statements include the accounts of all majority-owned, controlled subsidiaries. The Company operates in i one segment which focuses on oil and natural gas acquisition, production, exploration and development. Allocation of capital is made across the Company’s entire portfolio without regard to operating area. All intercompany accounts and transactions have been eliminated.
These unaudited condensed consolidated financial statements reflect, in the opinion of the Company’s management, all adjustments, consisting of normal and recurring adjustments, necessary to present fairly the financial position as of, and the results of operations for, the periods presented. Interim period results are not necessarily indicative of results of operations or cash flows for the full year and accordingly, certain information normally included in financial statements prepared in accordance with accounting principles generally accepted in the United States, has been condensed or omitted. During interim periods, Battalion follows the accounting policies disclosed in its Annual Report on Form 10-K, as filed with the United States Securities and Exchange Commission (SEC) on March 7, 2022. Please refer to the notes in the Annual Report on Form 10-K for the year ended December 31, 2021 when reviewing interim financial results. The Company has evaluated events or transactions through the date of issuance of these unaudited condensed consolidated financial statements.
/ iRisk and Uncertainties
The Company is continuously monitoring the current and potential impacts of the novel coronavirus (COVID-19) pandemic on its business, including how it has and may continue to impact its operations, financial results, liquidity, contractors, customers, employees and vendors, and taking appropriate actions in response, including implementing various measures to ensure the continued operation of its business in a safe and secure manner.
During 2021, widespread availability of COVID-19 vaccines in the United States and elsewhere combined with accommodative governmental monetary and fiscal policies and other factors, led to a rebound in demand for oil and natural gas and increases in oil and natural gas prices. Further, in 2022, the effects of Russian sanctions amidst the conflict with Ukraine have pushed oil and gas prices higher. However, there remains the potential for demand for oil and natural gas to be adversely impacted by the economic effects of rising interest rates and tightening monetary policies, as well as the ongoing COVID-19 pandemic, including as a consequence of the circulation of more infectious “variants” of the disease, vaccine hesitancy, waning vaccine effectiveness or other factors. As a consequence, the Company is unable to predict whether oil and natural gas prices will remain at current levels or will be adversely impacted by these or other factors. The results presented in this Form 10-Q are not necessarily indicative of future operating results.
Additionally, in periods of increasing commodity prices, the Company continues to be at risk to supply chain issues, including, but not limited to, labor shortages, pipe restrictions and potential delays in obtaining frac and/or drilling related equipment that could impact our business. During these periods, the costs and delivery times of rigs, equipment and supplies may also be substantially greater. The unavailability or high cost of drilling rigs and/or frac crews, pressure pumping equipment, tubulars and other supplies, and of qualified personnel can materially and adversely affect our operations and profitability.
For further information regarding the actual and potential impacts of COVID-19 and supply chain issues on the Company, see “Risk Factors” in Item 1A of the Company’s Annual Report on Form 10-K for the year ended December 31, 2021.
/10
BATTALION OIL CORPORATION
NOTES TO THE UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (continued)
Use of Estimates
The preparation of the Company’s unaudited condensed consolidated financial statements in conformity with accounting principles generally accepted in the United States requires the Company’s management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities, if any, at the date of the unaudited condensed consolidated financial statements and the reported amounts of revenues and expenses during the respective reporting periods. Estimates and assumptions that, in the opinion of management of the Company, are significant include oil and natural gas revenue accruals, capital and operating expense accruals, oil and natural gas reserves, depletion relating to oil and natural gas properties, asset retirement obligations, and fair value estimates. The Company bases its estimates and judgments on historical experience and on various other assumptions and information believed to be reasonable under the circumstances. Estimates and assumptions about future events and their effects cannot be predicted with certainty and, accordingly, these estimates may change as new events occur, as more experience is acquired, as additional information is obtained and as the Company’s operating environment changes. Actual results may differ from the estimates and assumptions used in the preparation of the Company’s unaudited condensed consolidated financial statements.
iCash, Cash Equivalents and Restricted Cash
The Company considers all highly liquid short-term investments with a maturity of three months or less at the time of purchase to be cash equivalents. These investments are carried at cost, which approximates fair value. Amounts in the unaudited condensed consolidated balance sheets included in “Cash and cash equivalents” and “Restricted cash” reconcile to the Company’s unaudited condensed statements of cash flows as follows:
i
| | | | | | |
|
| | ||||
| | | | | | |
Cash and cash equivalents | | $ | i 43,640 | | $ | i 46,864 |
Restricted cash | | | i 135 | | | i 1,495 |
Total cash, cash equivalents and restricted cash | | $ | i 43,775 | | $ | i 48,359 |
Restricted cash consists of funds to collateralize lines of credit.
/ iAccounts Receivable and Allowance for Doubtful Accounts
The Company’s accounts receivable are primarily receivables from joint interest owners and oil and natural gas purchasers. Accounts receivable are recorded at the amount due, less an allowance for doubtful accounts, when applicable. The Company establishes provisions for losses on accounts receivable if it determines that collection of all or part of the outstanding balance is doubtful. The Company regularly reviews collectability and establishes or adjusts the allowance for doubtful accounts as necessary using the specific identification method. As of June 30, 2022 and December 31, 2021, allowances for doubtful accounts were approximately $ i i 0.2 / million for both periods.
/Concentrations of Credit Risk
iThe Company’s primary concentrations of credit risk are the risks of uncollectible accounts receivable and of nonperformance by counterparties under the Company’s derivative contracts. Each reporting period, the Company assesses the recoverability of material receivables using historical data, current market conditions and reasonable and supportable forecasts of future economic conditions to determine expected collectability of its material receivables.
The Company’s exposure to credit risk under its derivative contracts is varied among major financial institutions with investment grade credit ratings, where it has master netting agreements which provide for offsetting of amounts
11
BATTALION OIL CORPORATION
NOTES TO THE UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (continued)
payable or receivable between the Company and the counterparty. To manage counterparty risk associated with derivative contracts, the Company selects and monitors counterparties based on an assessment of their financial strength and/or credit ratings. At June 30, 2022, the Company’s derivative counterparties include two major financial institutions, both of which are secured lenders under the Term Loan Agreement.
iRecently Issued Accounting Pronouncements
In March 2020, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update (ASU) No. 2020-04, Reference Rate Reform (Topic 848) (ASU 2020-04), in response to the risk of cessation of the London Interbank Offered Rate (LIBOR). This amendment provides optional expedients and exceptions for applying generally accepted accounting principles to contracts, hedging arrangements, and other transactions that reference LIBOR. ASU 2020-04 will be in effect through December 31, 2022. As of the date of this filing, ASU 2020-04 has not had a material impact on the Company’s operating results, financial position and disclosures.
i2. LEASES
The Company leases equipment and office space pursuant to net operating leases. Operating leases where the Company is the lessee are included in “Operating lease right of use assets” and “Operating lease liabilities” on the unaudited condensed consolidated balance sheets. The lease liabilities are initially and subsequently measured at the present value of the unpaid lease payments at the lease commencement date. The Company has no leases that meet the criteria for classification as a finance lease.
Variable lease payments associated with the Company’s leases are recognized when the event, activity, or circumstance in the lease agreement on which those payments are assessed occurs. Variable lease payments, when applicable, are presented as “Gathering and other” or “General and administrative” in the unaudited condensed consolidated statements of operations in the same line item as the expense arising from the fixed lease payments on the operating leases.
The Company elected not to recognize right of use assets and lease liabilities for all short-term leases that have a lease term of 12 months or less. The Company recognizes the lease payments associated with its short-term leases when incurred. Variable lease payments associated with these leases are recognized and presented in the same manner as for all other leases.
The “Operating lease right of use assets” outstanding on the unaudited condensed consolidated balance sheets as of June 30, 2022 and December 31, 2021 both have initial lease terms of i i 2.3 / years. Payments due under the lease contracts include fixed payments plus, in some instances, variable payments. i The table below summarizes the Company’s leases for the six months ended June 30, 2022 and 2021 (in thousands, except term and discount rate):
/12
BATTALION OIL CORPORATION
NOTES TO THE UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (continued)
| | | | | | | | |
| | Six Months Ended | | |||||
| | | ||||||
|
| 2022 | |
| 2021 |
| ||
Lease cost | | | | | | | | |
Operating lease costs | | $ | i 196 | | | $ | i 235 | |
Short-term lease costs | | | i 4,003 | | | | i 1,889 | |
Variable lease costs | | | — | | | | i 229 | |
Total lease costs | | $ | i 4,199 | | | $ | i 2,353 | |
| | | | | | | | |
Other information | | | | | | | | |
Cash paid for amounts included in the measurement of lease liabilities | | | | | | | | |
Operating cash flows from operating leases | | $ | i 196 | | | $ | i 328 | |
Weighted-average remaining lease term - operating leases | | | i 1.4 | years | | | i 0.2 | years |
Weighted-average discount rate - operating leases | | | i 4.29 | % | | | i 3.70 | % |
i Future minimum lease payments associated with the Company’s non-cancellable operating leases for office space as of June 30, 2022 are presented in the table below (in thousands):
| | | |
|
| ||
Remaining period in 2022 | | $ | i 196 |
2023 | | | i 359 |
2024 | | | — |
2025 | | | — |
2026 | | | — |
Thereafter | | | — |
Total operating lease payments | | | i 555 |
Less: discount to present value | | | i 16 |
Total operating lease liabilities | | | i 539 |
Less: current operating lease liabilities | | | i 377 |
Noncurrent operating lease liabilities | | $ | i 162 |
i3. OPERATING REVENUES
Substantially all of the Company’s revenues are derived from single basin operations, the Delaware Basin in Pecos, Reeves, Ward and Winkler Counties, Texas. Revenue is presented disaggregated in the statement of operations by major product, and depicts how the nature, timing, and uncertainty of revenue and cash flows are affected by economic factors in the Company’s single basin operations.
Revenue is recognized when the following five steps are completed: (1) identify the contract with the customer, (2) identify the performance obligation (promise) in the contract, (3) determine the transaction price, (4) allocate the transaction price to the performance obligations in the contract, (5) recognize revenue when the reporting organization satisfies a performance obligation. Revenues from the sale of crude oil, natural gas and natural gas liquids are recognized, at a point in time, when a performance obligation is satisfied by the transfer of control of the commodity to the customer. Revenue is measured based on consideration specified in a contract with a customer and excludes amounts collected on behalf of third parties. Taxes assessed by a governmental authority that are both imposed on and concurrent with a specific revenue-producing transaction that are collected by the Company from a customer are excluded from revenue. Because the Company’s performance obligations have been satisfied and an unconditional right
13
BATTALION OIL CORPORATION
NOTES TO THE UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (continued)
to consideration exists as of the balance sheet date, the Company recognized amounts due from contracts with customers of $ i 47.6 million and $ i 35.1 million as of June 30, 2022 and December 31, 2021, respectively, as “Accounts receivable” and “Other assets” on the unaudited condensed consolidated balance sheets.
i4. OIL AND NATURAL GAS PROPERTIES
The Company uses the full cost method of accounting for its investment in oil and natural gas properties. Under this method of accounting, all costs of acquisition, exploration and development of oil and natural gas reserves (including such costs as leasehold acquisition costs, geological expenditures, treating equipment and gathering support facilities costs, dry hole costs, tangible and intangible development costs and direct internal costs) are capitalized as the cost of oil and natural gas properties when incurred. To the extent capitalized costs of evaluated oil and natural gas properties, net of accumulated depletion, exceed the discounted future net revenues of proved oil and natural gas reserves, net of deferred taxes, such excess capitalized costs are charged to expense.
Additionally, the Company assesses all properties classified as unevaluated property on a quarterly basis for possible impairment. The Company assesses properties on an individual basis or as a group, if properties are individually insignificant. The assessment includes consideration of the following factors, among others: intent to drill; remaining lease term; geological and geophysical evaluations; drilling results and activity; the assignment of proved reserves; and the economic viability of development if proved reserves are assigned. During any period in which these factors indicate impairment, the cumulative drilling costs incurred to date for such property and all or a portion of the associated leasehold costs are transferred to the full cost pool and are then subject to depletion and the full cost ceiling test limitation.
At June 30, 2022, the ceiling test value of the Company’s reserves was calculated based on the first-day-of-the-month average for the 12-months ended June 30, 2022 of the West Texas Intermediate (WTI) crude oil spot price of $ i 85.82 per barrel, adjusted by lease or field for quality, transportation fees, and regional price differentials, and the first-day-of-the-month average for the 12-months ended June 30, 2022 of the Henry Hub natural gas price of $ i 5.13 per MMBtu, adjusted by lease or field for energy content, transportation fees, and regional price differentials. Using these prices, the Company’s net book value of oil and natural gas properties at June 30, 2022 did not exceed the ceiling amount.
At June 30, 2021, the ceiling test value of the Company’s reserves was calculated based on the first-day-of-the-month average for the 12-months ended June 30, 2021 of the WTI crude oil spot price of $ i 49.72 per barrel, adjusted by lease or field for quality, transportation fees, and regional price differentials, and the first-day-of-the-month average for the 12-months ended June 30, 2021 of the Henry Hub natural gas price of $ i 2.43 per MMBtu, adjusted by lease or field for energy content, transportation fees, and regional price differentials. Using these prices, the Company’s net book value of oil and natural gas properties at June 30, 2021 did not exceed the ceiling amount.
Changes in commodity prices, production rates, levels of reserves, future development costs, transfers of unevaluated properties to the full cost pool, capital spending, and other factors will determine the Company’s ceiling test calculation and impairment analyses in future periods.
/
14
BATTALION OIL CORPORATION
NOTES TO THE UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (continued)
5. DEBT
iAs of June 30, 2022 and December 31, 2021, the Company’s debt consisted of the following (in thousands):
| | | | | | | |
| | | | ||||
Term loan credit facility(1) | | $ | i 203,372 | | | $ | i 181,565 |
Paycheck Protection Program loan | | | — | | | | i 85 |
Total debt, net | | | i 203,372 | | | | i 181,650 |
Current portion of long-term debt(2) | | | i 15,000 | | | | i 85 |
Total long-term debt, net | | $ | i 188,372 | | | $ | i 181,565 |
| (1) | Amount is net of $ i 12.4 million and $ i 14.2 million in unamortized debt issuance costs at June 30, 2022 and December 31, 2021, respectively. Amount also excludes the initial fair value allocated to the change of control call option embedded derivative of $ i i 4.2 / million. Refer to “Term Loan Credit Facility” below for further details. |
| (2) | As of June 30, 2022, amount represents amortization payments of $ i 15.0 million under the Term Loan Agreement due within one year. As of December 31, 2021, amount represents the balance owed under the Company’s Paycheck Protection Program Loan. |
Term Loan Credit Facility
On November 24, 2021, the Company and its wholly owned subsidiary, Halcón Holdings, LLC (Borrower) entered into an Amended and Restated Senior Secured Credit Agreement (Term Loan Agreement) with Macquarie Bank Limited, as administrative agent, and certain other financial institutions party thereto, as lenders. The Term Loan Agreement amends and restates in its entirety the senior secured revolving credit agreement, as amended, (the Senior Credit Agreement) entered into in 2019 as further discussed in our Annual Report on Form 10-K for the fiscal year ended December 31, 2021. Pursuant to the Term Loan Agreement, the lenders have agreed to loan the Company (i) $ i 200.0 million, which was funded on November 24, 2021 and was partially used to refinance all amounts owed under the Senior Credit Agreement; (ii) up to $ i 20.0 million under the first delayed draw of the Term Loan Agreement, which was drawn on April 29, 2022 and (iii) up to $ i 15.0 million, which amount will be available to be drawn from the date certain wells included in the approved plan of development (APOD) are deemed producing APOD wells until up to i 18 months after November 24, 2021, subject to the satisfaction of certain conditions. An additional $ i 5.0 million is available for the issuance of letters of credit. The maturity date of the Term Loan Agreement is i November 24, 2025. Until such maturity date, borrowings under the Term Loan Agreement bear interest at a rate per annum equal to LIBOR (or another applicable reference rate, as determined pursuant to the provisions of the Term Loan Agreement) plus an applicable margin of i 7.00%.
At June 30, 2022, the Company had $ i 220.0 million indebtedness outstanding and approximately $ i 1.3 million letters of credit outstanding under the Term Loan Agreement. The Company also has available $ i 15.0 million in delayed draw term loans, subject to the satisfaction of certain conditions defined in the agreement.
The Company may elect, at its option, to prepay any borrowing outstanding under the Term Loan Agreement subject to the following prepayment premiums:
i
| | | |
Period | | | Premium |
Months i 0 - i 12 | | | Make-whole amount equal to 12 months of interest plus i 2.00% |
Months i 13 - i 24 | | | i 2.00% |
Months i 25 - i 36 | | | i 1.00% |
Months i 37 - i 48 | | | i 0.00% |
15
BATTALION OIL CORPORATION
NOTES TO THE UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (continued)
The Company may be required to make mandatory prepayments under the Term Loan Agreement in connection with the incurrence of non-permitted debt, certain asset sales, or with cash on hand in excess of certain maximum levels beginning in 2023. For each fiscal quarter after January 1, 2023, the Company is required to make mandatory prepayments when the Consolidated Cash Balance, as defined in the Term Loan Agreement, exceeds $ i 20.0 million. Until December 31, 2024, the forecasted APOD capital expenditures for the succeeding fiscal quarter are excluded for purposes of determining the Consolidated Cash Balance.
The Company is required to make scheduled amortization payments in the aggregate amount of $ i 120.0 million from the fiscal quarter ending March 31, 2023 through the fiscal quarter ending September 30, 2025. Amounts outstanding under the Term Loan Agreement are guaranteed by certain of the Borrower’s direct and indirect subsidiaries and secured by substantially all of the assets of the Borrower and such direct and indirect subsidiaries, and by the equity interests of the Borrower held by the Company. As part of the Term Loan Agreement there are certain restrictions on the transfer of assets, including cash, to Battalion from the guarantor subsidiaries.
The Term Loan Agreement also contains certain financial covenants (as defined in the Term Loan Agreement), including the maintenance of the following ratios:
| ● | Asset Coverage Ratio of not less than i 1.60 to i 1.00 as of June 30, 2022, i 1.70 to i 1.00 as of September 30, 2022, and i 1.80 to i 1.00 as of December 31, 2022 and each fiscal quarter thereafter |
| ● | Total Net Leverage Ratio of not greater than i 3.25 to i 1.00 as of June 30, 2022, i 3.00 to i 1.00 as of September 30, 2022 and December 31, 2022, i 2.75 to i 1.00 as of March 31, 2023, and i 2.50 to i 1.00 as of each fiscal quarter thereafter, and |
| ● | Current Ratio of not less than i 1.00 to i 1.00, each determined as of the last day of any fiscal quarter period. |
i As of June 30, 2022, the Company was in compliance with the financial covenants under the Term Loan Agreement.
The Term Loan Agreement also contains an APOD for the Company’s Monument Draw acreage through the drilling and completion of certain wells. The Term Loan Agreement contains a proved developed producing production test and an APOD economic test which the Company must maintain compliance with otherwise, subject to any available remedies or waivers, the Company is required to immediately cease making expenditures in respect of the APOD other than any expenditures deemed necessary by the Company in respect of no more than six additional APOD wells.
The Term Loan Agreement also contains certain events of default, including non-payment; breaches of representations and warranties; non-compliance with covenants or other agreements; cross-default to material indebtedness; judgments; change of control; and voluntary and involuntary bankruptcy.
In conjunction with the Term Loan Agreement, the Company agreed to pay a premium to the lenders upon a future change of control event in which a majority of the board of directors or the Chief Executive Officer or the Chief Financial Officer positions do not remain held by the same persons as before the change of control event (Change of Control Call Option). The premium is reduced over time through the payment of interest and certain fees. The Company determined that the Change of Control Call Option was an embedded derivative, concluded the embedded derivative was not clearly and closely related to the host debt instrument, and recorded the initial $ i 4.2 million fair value separately on the unaudited condensed consolidated balance sheet within “Other noncurrent liabilities.” The Change of Control Call Option is subsequently remeasured at fair value each reporting period with fair value changes recorded in “Interest expense and other” on the unaudited consolidated statements of operations. Refer to Note 6 “Fair Value Measurements,” for a discussion of the valuation approach used, the significant inputs to the valuation, and for a reconciliation of the change in fair value of the Change of Control Call Option.
16
BATTALION OIL CORPORATION
NOTES TO THE UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (continued)
Paycheck Protection Program Loan
In 2020, the Company entered into a promissory note (the PPP Loan) for a principal amount of approximately $ i 2.2 million under the Paycheck Protection Program of the CARES Act. Effective August 13, 2021, the principal amount of the Company’s PPP Loan was reduced to approximately $ i 0.2 million upon forgiveness of $ i 2 million based on the use of loan proceeds for eligible expenses under the CARES Act. The Company recorded a gain on the extinguishment of the forgiven portion of the PPP Loan and related accrued interest of $ i 2.1 million presented in “Gain (loss) on extinguishment of debt” in the consolidated statements of operations during the quarter ended September 30, 2021. During the first quarter of 2022, the $ i 0.2 million principal amount of the PPP loan was repaid in full.
i6. FAIR VALUE MEASUREMENTS
The Company’s determination of fair value incorporates not only the credit standing of the counterparties involved in transactions with the Company resulting in receivables on the Company’s unaudited condensed consolidated balance sheets, but also the impact of the Company’s nonperformance risk on its own liabilities. Fair value is defined as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). The Company separates the fair value of its financial instruments using a fair value hierarchy that prioritizes the inputs to valuation techniques used to measure fair value. The hierarchy assigns the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1) and the lowest priority to unobservable inputs (Level 3). Level 2 measurements are inputs that are observable for assets or liabilities, either directly or indirectly, other than quoted prices included within Level 1. The Company utilizes market data or assumptions that market participants would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. These inputs can be readily observable, market corroborated, or generally unobservable. The Company classifies fair value balances based on the observability of those inputs.
A financial instrument’s level within the fair value hierarchy is 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 fair value assets and liabilities and their placement within the fair value hierarchy levels. There were i no transfers between fair value hierarchy levels for any period presented. The following tables set forth by level within the fair value hierarchy the Company’s financial assets and liabilities associated with commodity-based derivative contracts that were accounted for at fair value as of June 30, 2022 and December 31, 2021 (in thousands):
i
| | | | | | | | | | | | |
| | |||||||||||
|
| Level 1 |
| Level 2 |
| Level 3 |
| Total | ||||
Assets | | | | | | | | | | | | |
Assets from commodity-based derivative contracts | | $ | — | | $ | i 10,118 | | $ | — | | $ | i 10,118 |
| | | | | | | | | | | | |
Liabilities | | | | | | | | | | | | |
Liabilities from commodity-based derivative contracts | | $ | — | | $ | i 149,888 | | $ | — | | $ | i 149,888 |
| | | | | | | | | | | | |
| | |||||||||||
|
| Level 1 |
| Level 2 |
| Level 3 |
| Total | ||||
Assets | | | | | | | | | | | | |
Assets from commodity-based derivative contracts | | $ | — | | $ | i 3,898 | | $ | — | | $ | i 3,898 |
| | | | | | | | | | | | |
Liabilities | | | | | | | | | | | | |
Liabilities from commodity-based derivative contracts | | $ | — | | $ | i 65,466 | | $ | — | | $ | i 65,466 |
/17
BATTALION OIL CORPORATION
NOTES TO THE UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (continued)
Derivative contracts listed above as Level 2 include fixed-price swaps, collars, basis swaps and WTI NYMEX rolls that are carried at fair value. The Company records the net change in the fair value of these positions in “Net gain (loss) on derivative contracts” in the Company’s unaudited condensed consolidated statements of operations. The Level 2 observable data includes the forward curves for commodity prices based on quoted market prices and implied volatility factors related to changes in the forward curves. See Note 7, “Derivative and Hedging Activities,” for additional discussion of derivatives.
The Company’s derivative contracts are with major financial institutions with investment grade credit ratings which are believed to have minimal credit risk. As such, the Company is exposed to credit risk to the extent of nonperformance by the counterparties in the derivative contracts; however, the Company does not anticipate such nonperformance.
As discussed in Note 5, “Debt,” the Company recorded the fair value of the Change of Control Call Option separately on the unaudited condensed consolidated balance sheets in “Other noncurrent liabilities.” The fair value of the Change of Control Call Option is subsequently remeasured each reporting period with fair value changes recorded in “Interest expense and other” on the unaudited consolidated statements of operations. The valuation of the Change of Control Call Option includes significant inputs such as the timing and probability of discrete potential exit scenarios, forward LIBOR curves, and discount rates based on implied and market yields. i The following table sets forth a reconciliation of the changes in fair value of the Change of Control Call Option classified as Level 3 in the fair value hierarchy (in thousands):
| | | |
| | Change of Control | |
| | Call Option | |
Balance at December 31, 2021 | | $ | i 4,003 |
Change in fair value | | | ( i 2,595) |
Balance at June 30, 2022 | | $ | i 1,408 |
Estimated fair value amounts have been determined at discrete points in time based on relevant market information. These estimates involve uncertainties and cannot be determined with precision. The estimated fair value of cash, cash equivalents and restricted cash, accounts receivable, and accounts payable approximates their carrying value due to their short-term nature. The estimated fair value of borrrowings under the Company’s Term Loan Agreement approximates carrying value because the interest rates approximate current market rates.
The Company follows the provisions of ASC 820, for nonfinancial assets and liabilities measured at fair value on a non-recurring basis. These provisions apply to the Company’s initial recognition of asset retirement obligations for which fair value is used. The asset retirement obligation estimates are derived from historical costs and management’s expectation of future cost environments; and therefore, the Company has designated these liabilities as Level 3. See Note 8, “Asset Retirement Obligations,” for a reconciliation of the beginning and ending balances of the liability for the Company’s asset retirement obligations.
i7. DERIVATIVE AND HEDGING ACTIVITIES
The Company is exposed to certain risks relating to its ongoing business operations, such as commodity price risk and interest rate risk. In accordance with the Company’s policy and the requirements under the Term Loan Agreement, it generally hedges a substantial, but varying, portion of anticipated oil and natural gas production for future periods. Derivatives are carried at fair value on the unaudited condensed consolidated balance sheets as assets or liabilities, with the changes in the fair value included in the unaudited condensed consolidated statements of operations for the period in which the change occurs. The Company has elected not to designate any of its derivative contracts for hedge accounting. Accordingly, the Company records the net change in the mark-to-market valuation of these derivative contracts, as well as all payments and receipts on settled derivative contracts, in “Net gain (loss) on derivative contracts” on the unaudited condensed consolidated statements of operations. The Company’s hedge policies and objectives may change
18
BATTALION OIL CORPORATION
NOTES TO THE UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (continued)
significantly as its operational profile changes. The Company does not enter into derivative contracts for speculative trading purposes.
It is the Company’s policy to enter into derivative contracts only with counterparties that are creditworthy financial or commodity hedging institutions deemed by management as competent and competitive market makers. As of June 30, 2022, the Company did not post collateral under any of its derivative contracts as they are secured under the Company’s Term Loan Agreement.
The Company’s crude oil, and natural gas derivative positions at any point in time may consist of fixed-price swaps, costless put/call collars, basis swaps and WTI NYMEX rolls further described as follows:
| ● | Fixed-price swaps are designed so that the Company receives or makes payments based on a differential between fixed and variable prices for crude oil and natural gas. |
| ● | Costless collars consist of a sold call, which establishes a maximum price the Company will receive for the volumes under contract and a purchased put that establishes a minimum price and are generally utilized less frequently by the Company than fixed-price swaps. |
| ● | Basis swaps effectively lock in a price differential between regional prices (i.e. Midland) where the product is sold and the relevant pricing index under which the oil production is hedged (i.e. Cushing). |
| ● | WTI NYMEX roll agreements account for pricing adjustments to the trade month versus the delivery month for contract pricing. |
The following table summarizes the location and fair value amounts of all derivative contracts in the unaudited condensed consolidated balance sheets as of June 30, 2022 and December 31, 2021 (in thousands):
| | | | | | | | | | | | | | | | |
Derivatives not designated as | | | | Asset derivative contracts | | | | Liability derivative contracts | ||||||||
hedging contracts under ASC 815 |
| Balance sheet location |
|
|
| Balance sheet location |
|
| ||||||||
Commodity contracts | | Current assets - assets from derivative contracts | | $ | i 6,146 | | $ | i 1,383 | | Current liabilities - liabilities from derivative contracts | | $ | ( i 91,750) | | $ | ( i 58,322) |
Commodity contracts | | Other noncurrent assets - assets from derivative contracts | | | i 3,972 | | | i 2,515 | | Other noncurrent liabilities - liabilities from derivative contracts | | | ( i 58,138) | | | ( i 7,144) |
Total derivatives not designated as hedging contracts under ASC 815 | | | | $ | i 10,118 | | $ | i 3,898 | | | | $ | ( i 149,888) | | $ | ( i 65,466) |
19
BATTALION OIL CORPORATION
NOTES TO THE UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (continued)
The following table summarizes the location and amounts of the Company’s realized and unrealized gains and losses on derivative contracts in the Company’s unaudited condensed consolidated statements of operations (in thousands):
| | | | | | | | | | | | | | |
| | | | Amount of gain or (loss) | | Amount of gain or (loss) | ||||||||
| | | | recognized in income on | | recognized in income on | ||||||||
| | | | derivative contracts for the | | derivative contracts for the | ||||||||
Derivatives not designated | | Location of gain or | | Three Months Ended | | Six Months Ended | ||||||||
as hedging contracts | | (loss) recognized in income | | June 30, | | June 30, | ||||||||
under ASC 815 |
| on derivative contracts | | 2022 | | 2021 | | 2022 | | 2021 | ||||
Commodity contracts: | | | | | | | | | | | | | | |
Unrealized gain (loss) on commodity contracts | | Other income (expenses) - net gain (loss) on derivative contracts | | $ | i 12,837 | | $ | ( i 34,817) | | $ | ( i 78,201) | | $ | ( i 70,869) |
Realized gain (loss) on commodity contracts | | Other income (expenses) - net gain (loss) on derivative contracts | | | ( i 44,747) | | | ( i 18,272) | | | ( i 77,567) | | | ( i 27,931) |
Total net gain (loss) on derivative contracts | | | | $ | ( i 31,910) | | $ | ( i 53,089) | | $ | ( i 155,768) | | $ | ( i 98,800) |
iAt June 30, 2022, the Company had the following open crude oil and natural gas derivative contracts:
| | | | | | | | | | | | | | | |
Instrument |
| | 2022 |
| | 2023 |
| | 2024 |
| | 2025 | | | 2026 |
Crude oil fixed-price swap: | | | | | | | | | | | | | | | |
Total volumes (Bbls) | | | i 1,240,865 | | | i 2,000,965 | | | i 1,449,140 | | | i 1,028,160 | | | i 212,810 |
Weighted average price | | $ | i 52.80 | | | i 65.75 | | | i 60.91 | | | i 59.69 | | | i 59.83 |
Crude oil basis swap: | | | | | | | | | | | | | | | |
Total volumes (Bbls) | | | i 1,222,565 | | | i 1,937,165 | | | i 1,413,120 | | | i 1,000,360 | | | i 212,810 |
Weighted average price | | $ | i 0.41 | | | i 0.25 | | | i 0.23 | | | i 0.17 | | | i 0.19 |
Crude oil WTI NYMEX roll: | | | | | | | | | | | | | | | |
Total volumes (Bbls) | | | i 1,005,565 | | | i 1,937,165 | | | i 1,413,120 | | | i 1,000,360 | | | i 212,810 |
Weighted average price | | $ | i 0.10 | | | i 0.50 | | | i 0.28 | | | i 0.10 | | | i 0.27 |
Natural gas fixed-price swap: | | | | | | | | | | | | | | | |
Total volumes (MMBtu) | | | i 1,167,500 | | | i 3,957,750 | | | i 2,658,750 | | | i 2,428,050 | | | |
Weighted average price | | $ | i 3.92 | | | i 3.36 | | | i 3.09 | | | i 3.00 | | | |
Natural gas producer two-way collar: | | | | | | | | | | | | | | | |
Total volumes (MMBtu) | | | i 2,473,400 | | | i 1,742,100 | | | i 1,424,100 | | | i 555,700 | | | i 653,900 |
Weighted average price (call) | | $ | i 3.97 | | | i 5.52 | | | i 4.70 | | | i 4.24 | | | i 4.45 |
Weighted average price (put) | | $ | i 3.48 | | | i 3.86 | | | i 3.19 | | | i 3.28 | | | i 4.00 |
Natural gas basis swap: | | | | | | | | | | | | | | | |
Total volumes (MMBtu) | | | i 3,640,900 | | | i 5,700,600 | | | i 4,084,350 | | | i 2,983,750 | | | i 653,900 |
Weighted average price | | $ | ( i 0.51) | | | ( i 0.64) | | | ( i 0.64) | | | ( i 0.56) | | | ( i 0.96) |
/20
BATTALION OIL CORPORATION
NOTES TO THE UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (continued)
The Company presents the fair value of its derivative contracts at the gross amounts in the unaudited condensed consolidated balance sheets. The following table shows the potential effects of master netting arrangements on the fair value of the Company’s derivative contracts at June 30, 2022 and December 31, 2021 (in thousands):
i
| | | | | | | | | | | | |
| | Derivative Assets | | Derivative Liabilities | ||||||||
Offsetting of Derivative Assets and Liabilities |
|
|
|
| ||||||||
| | | | | | | | | | | | |
Gross Amounts Presented in the Consolidated Balance Sheet | | $ | i 10,118 | | $ | i 3,898 | | $ | ( i 149,888) | | $ | ( i 65,466) |
Amounts Not Offset in the Consolidated Balance Sheet | | | ( i 10,118) | | | ( i 3,898) | | | i 10,118 | | | i 3,898 |
Net Amount | | $ | i — | | $ | i — | | $ | ( i 139,770) | | $ | ( i 61,568) |
The Company enters into an International Swap Dealers Association Master Agreement (ISDA) with each counterparty prior to a derivative contract with such counterparty. The ISDA is a standard contract that governs all derivative contracts entered into between the Company and the respective counterparty. The ISDA allows for offsetting of amounts payable or receivable between the Company and the counterparty, at the election of both parties, for transactions that occur on the same date and in the same currency.
i8. ASSET RETIREMENT OBLIGATIONS
The Company records an asset retirement obligation (ARO) on oil and natural gas properties when it can reasonably estimate the fair value of an obligation to perform site reclamation, dismantle facilities or plug and abandon costs. The Company records the ARO liability on the unaudited condensed consolidated balance sheets and capitalizes the cost in “Oil and natural gas properties” during the period in which the obligation is incurred. The Company records the accretion of its ARO liabilities in “Depletion, depreciation and accretion” expense in the unaudited condensed consolidated statements of operations. The additional capitalized costs are depreciated on a unit-of-production basis.
iThe Company recorded the following activity related to its ARO liability (in thousands):
| | | |
Liability for asset retirement obligations as of December 31, 2021 |
| $ | i 11,896 |
Liabilities incurred during the period | | | i 103 |
Liabilities settled during the period | | | ( i 132) |
Accretion expense | | | i 220 |
Liability for asset retirement obligations as of June 30, 2022 | | $ | i 12,087 |
/
i9. COMMITMENTS AND CONTINGENCIES
Commitments
As of June 30, 2022, the Company has a minimum volume commitment with a third party for the purchase of chemicals to treat sour gas production through December 31, 2022. The future payments associated with the minimum volume commitment are approximately $ i 3.3 million.
As of June 30, 2022, the Company has an active drilling rig commitment of approximately $ i 1.7 million through the third quarter of 2022. Termination of the active drilling rig commitment would require an early termination penalty of
/21
BATTALION OIL CORPORATION
NOTES TO THE UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (continued)
$ i 0.6 million, which would be in lieu of paying the active drilling rig commitment of $ i 1.7 million. In July 2022, we extended our drilling rig commitment through the fourth quarter of 2022.
The Company has entered into various long-term gathering, transportation and sales contracts with respect to its oil and natural gas production from the Delaware Basin in West Texas. As of June 30, 2022, the Company had in place i two long-term crude oil contracts and i 12 long-term natural gas contracts in this area and the sales prices under these contracts are based on posted market rates. Under the terms of these contracts, the Company has committed a substantial portion of its production from this area for periods ranging from one to twenty years from the date of first production.
Contingencies
In addition to the matter described below, from time to time, the Company may be a plaintiff or defendant in a pending or threatened legal proceeding arising in the normal course of its business. While the outcome and impact of currently pending legal proceedings cannot be determined, the Company’s management and legal counsel believe that the resolution of these proceedings through settlement or adverse judgment will not have a material effect on the Company’s unaudited condensed consolidated operating results, financial position or cash flows.
Surface owners of properties in Louisiana, where the Company formerly operated, often file lawsuits or assert claims against oil and gas companies claiming that operators and working interest owners are liable for environmental damages arising from operations conducted on the leased properties. These damages are frequently measured by the cost to restore the leased properties to their original condition. Currently and in the past, the Company has been party to such matters in Louisiana. With regard to pending matters, the overall exposure is not currently determinable. The Company intends to vigorously oppose these claims.
i10. STOCKHOLDERS’ EQUITY
Incentive Plans
The Company’s board of directors has adopted the 2020 Long-Term Incentive Plan (the Plan), as amended in 2021, in which an aggregate of approximately i 1.8 million shares of the Company’s common stock were available for grant pursuant to awards under the Plan. As of June 30, 2022, a maximum of i 0.3 million of the Company’s common stock remained reserved for issuance under the Plan. For the six months ended June 30, 2022 and 2021, the Company recognized expense of $ i 0.9 million and $ i 1.1 million, respectively, related to stock-based-compensation awards granted to employees and directors, including grants of stock options and restricted stock. Stock-based compensation expense is recorded as a component of "General and administrative" on the unaudited condensed consolidated statements of operations.
Restricted Stock
From time to time, the Company grants shares of restricted stock units (RSUs) under the Plan to employees of the Company. Under the Plan, employee RSUs will generally vest and convert to shares in equal amounts over a three or i four year vesting period from the date of the grant, depending on award, or when the performance or market conditions described further described in our Annual Report on Form 10-K occur.
During the six months ended June 30, 2022, the Company granted i 0.2 million shares of RSUs at a weighted average grant date fair value of $ i 14.07 per share. At June 30, 2022, the Company had $ i 4.1 million of unrecognized compensation expense related to non-vested RSU awards to be recognized over a weighted average period of i 1.6 years.
/22
BATTALION OIL CORPORATION
NOTES TO THE UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (continued)
Stock Options
From time to time, the Company grants stock options under the Plan covering shares of common stock to employees of the Company. Stock options, when exercised, are settled through the payment of the exercise price in exchange for new shares of stock underlying the option. Awards granted under the Plan typically vest over a i four year period at a rate of one-fourth on the annual anniversary date of the grant and expire i seven years from the date of grant. i No stock options have been granted during the six month ended June 30, 2022. At June 30, 2022, the Company had $ i 0.3 million of unrecognized compensation expense related to non-vested stock options to be recognized over a weighted-average period of i 1.1 years.
Warrants
On October 8, 2019, the Company entered into a warrant agreement (the Warrant Agreement) with Broadridge Corporate Issuer Solutions, Inc. as the warrant agent, pursuant to which the Company issued approximately i 6.9 million warrants (Series A, Series B and Series C Warrants and together, the Warrants) with corresponding initial exercise prices ranging from $ i 40.17 to $ i 60.45 per share, on a pro rata basis to pre-emergence holders of the predecessor Company’s common stock pursuant to the Company’s plan of reorganization. The Warrants do not grant any voting or control rights or dividend rights, or contain any negative covenants restricting the operation of the Company’s business.
Each Warrant represents the right to purchase i one share of common stock at the applicable exercise prices, subject to adjustment as provided in the Warrant Agreement and increasing monthly at an annualized rate of i 6.75%, compounding monthly. Each series of Warrants issued under the Warrant Agreement has a i three-year term, expiring on i October 8, 2022. As of June 30, 2022, the Company had i 1.8 million Series A, i 2.2 million Series B and i 2.9 million Series C Warrants outstanding with corresponding exercise prices of $ i 46.15, $ i 55.86 and $ i 70.42 per share, respectively.
i11. EARNINGS PER SHARE
iThe following represents the calculation of earnings (loss) per share (in thousands, except per share amounts):
| | | | | | | | | | | | |
| | Three Months Ended | | Six Months Ended | ||||||||
| | June 30, | | |||||||||
|
| 2022 | | 2021 | | 2022 | | 2021 | ||||
Basic: | | | | | | | | | | | | |
Net income (loss) | | $ | i 13,047 | | $ | ( i 33,929) | | $ | ( i 79,697) | | $ | ( i 67,304) |
Weighted average basic number of common shares outstanding | | | i 16,338 | | | i 16,268 | | | i 16,320 | | | i 16,250 |
Basic net income (loss) per share of common stock | | $ | i 0.80 | | $ | ( i 2.09) | | $ | ( i 4.88) | | $ | ( i 4.14) |
| | | | | | | | | | | | |
Diluted: | | | | | | | | | | | | |
Net income (loss) | | $ | i 13,047 | | $ | ( i 33,929) | | $ | ( i 79,697) | | $ | ( i 67,304) |
Weighted average basic number of common shares outstanding | | | i 16,338 | | | i 16,268 | | | i 16,320 | | | i 16,250 |
Common stock equivalent shares representing shares issuable upon: | | | | | | | | | | | | |
Exercise of Series A Warrants | | | Anti-dilutive | | | Anti-dilutive | | | Anti-dilutive | | | Anti-dilutive |
Exercise of Series B Warrants | | | Anti-dilutive | | | Anti-dilutive | | | Anti-dilutive | | | Anti-dilutive |
Exercise of Series C Warrants | | | Anti-dilutive | | | Anti-dilutive | | | Anti-dilutive | | | Anti-dilutive |
Exercise of stock options | | | Anti-dilutive | | | Anti-dilutive | | | Anti-dilutive | | | Anti-dilutive |
Vesting of restricted stock units | | | i 172 | | | Anti-dilutive | | | Anti-dilutive | | | Anti-dilutive |
Weighted average diluted number of common shares outstanding | | | i 16,510 | | | i 16,268 | | | i 16,320 | | | i 16,250 |
Diluted net income (loss) per share of common stock | | $ | i 0.79 | | $ | ( i 2.09) | | $ | ( i 4.88) | | $ | ( i 4.14) |
/23
BATTALION OIL CORPORATION
NOTES TO THE UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (continued)
Common stock equivalents, including warrants and options totaling i 7.4 million for the quarter ended June 30, 2022 were not included in the computation of diluted earnings per share of common stock because the effect would have been anti-dilutive. Common stock equivalents, including warrants, options and restricted stock units, totaling i 7.7 million for the six months ended June 30, 2022 were not included in the computation of diluted earnings per share of common stock because the effect would have been anti-dilutive.
Common stock equivalents, including warrants, options and restricted stock units, totaling i 7.7 million for the six months ended June 30, 2021 were not included in the computation of diluted earnings per share of common stock because the effect would have been anti-dilutive.
i12. ADDITIONAL FINANCIAL STATEMENT INFORMATION
iCertain balance sheet amounts are comprised of the following (in thousands):
| | | | | | |
|
|
| ||||
Accounts receivable, net: | | | | | | |
Oil, natural gas and natural gas liquids revenues | | $ | i 47,221 | | $ | i 34,110 |
Joint interest accounts | | | i 5,590 | | | i 2,503 |
Other | | | i 191 | | | i 193 |
| | $ | i 53,002 | | $ | i 36,806 |
Prepaids and other: | | | | | | |
Prepaids | | $ | i 536 | | $ | i 975 |
Funds in escrow | | | i 390 | | | i 390 |
Other | | | i 1 | | | i 1 |
| | $ | i 927 | | $ | i 1,366 |
Other assets (Non-current): | | | | | | |
Investment in unconsolidated affiliate(1) | | $ | i 1,653 | | $ | — |
Oil, natural gas and natural gas liquids revenues | | | i 417 | | | i 1,010 |
Funds in escrow | | | i 1,228 | | | i 1,227 |
Other | | | i 31 | | | i 33 |
| | $ | i 3,329 | | $ | i 2,270 |
Accounts payable and accrued liabilities: | | | | | | |
Trade payables | | $ | i 36,885 | | $ | i 25,315 |
Accrued oil and natural gas capital costs | | | i 20,518 | | | i 4,881 |
Revenues and royalties payable | | | i 29,534 | | | i 22,763 |
Accrued interest expense | | | i 57 | | | i 42 |
Accrued employee compensation | | | i 2,073 | | | i 3,735 |
Accrued lease operating expenses | | | i 6,212 | | | i 6,090 |
Drilling advances from partners | | | i 2,055 | | | — |
| | $ | i 97,334 | | $ | i 62,826 |
| (1) | In May 2022, we entered into a joint venture with Caracara Services, LLC (“Caracara”) to develop an acid gas treatment facility to remove hydrogen sulfide and carbon dioxide from our produced natural gas. We also entered into a gas treating agreement with the joint venture, Brazos Amine Treater, LLC (“BAT”), and have a minimum volume commitment of i 20 MMcf per day, with certain rollover rights and start-up flexibility, for an initial term of i five years from the in service date of the facility. Caracara will provide all necessary capital for the construction of the treatment facility. We contributed certain full cost pool assets to the joint venture in exchange for a retained i 5% equity interest in BAT, an unconsolidated subsidiary. For accounting purposes, since we do not control the key activities (e.g. operating and maintaining the facility) which most significantly impact economic performance nor do we have the obligation to absorb losses or the right to receive benefits that could |
24
BATTALION OIL CORPORATION
NOTES TO THE UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (continued)
| potentially be significant, we are not the primary beneficiary of BAT. Accordingly, we account for our investment in BAT using the equity method of accounting based on our ability to exercise significant influence, but not control, over the key activities of the joint venture. |
25
ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
The following discussion is intended to assist in understanding our results of operations for the three and six months ended June 30, 2022 and 2021 and should be read in conjunction with our unaudited condensed consolidated financial statements and the notes thereto included in this Quarterly Report on Form 10-Q and with the consolidated financial statements, notes and management’s discussion and analysis of financial condition and results of operations included in our Annual Report on Form 10-K for the fiscal year ended December 31, 2021. The results presented in this Form 10-Q are not necessarily indicative of future operating results.
Statements in this discussion may be forward-looking. These forward-looking statements involve risks and uncertainties, including those discussed below, which could cause actual results to differ from those expressed. For more information, see “Special note regarding forward-looking statements.”
Overview
We are an independent energy company focused on the acquisition, production, exploration and development of onshore liquids-rich oil and natural gas assets in the United States. During 2017, we acquired certain properties in the Delaware Basin and divested our assets located in the Williston Basin in North Dakota and in the El Halcón area of East Texas. As a result, our properties and drilling activities are currently focused in the Delaware Basin, where we have an extensive drilling inventory that we believe offers attractive long-term economics.
Our total operating revenues for the first six months of 2022 and 2021 were $183.1 million and $119.9 million, respectively. The increase in revenues is primarily attributable to an approximate $23.62 per Boe increase in average realized prices (excluding the effects of hedging arrangements). During the first six months of 2022, production averaged 14,906 Boe/d compared to average production of 14,956 Boe/d during the six months of 2021. In February 2021, we temporarily shut-in production due to inclement weather. The estimated decrease in average daily oil and natural gas production associated with this temporary shut-in was approximately 600 Boe/d in the first six months of 2021. Current year production was impacted by natural production declines on our existing producing wells. For the six months ended June 30, 2022, we drilled and cased 5 gross (4.84 net) operated wells and completed and put online 5 gross and net operated wells.
Our financial results depend upon many factors, but are largely driven by the volume of our oil and natural gas production and the price that we receive for that production. Our production volumes will decline as reserves are depleted unless we expend capital in successful development and exploration activities or acquire properties with existing production. The amount we realize for our production depends predominantly upon commodity prices, which are affected by changes in market demand and supply, as impacted by overall economic activity, weather, transportation take-away capacity constraints, inventory storage levels, basis differentials and other factors. Accordingly, finding, developing and producing oil and natural gas reserves at economical costs are critical to our long-term success.
When commodity prices decline significantly our ability to finance our capital budget and operations may be adversely impacted. While we use derivative instruments to provide partial protection against declines in oil and natural gas prices, the total volumes we hedge are less than our expected production, vary from period to period based on our view of current and future market conditions, remain consistent with the requirements in effect under our Term Loan Agreement and extend, on a rolling basis, for the next four years. These limitations result in our liquidity being susceptible to commodity price declines. Additionally, while intended to reduce the effects of volatile commodity prices, derivative transactions may limit our potential gains and increase our potential losses if commodity prices were to rise substantially over the price established by the hedge. Our hedge policies and objectives may change significantly as our operational profile changes and/or commodities prices change. We do not enter into derivative contracts for speculative trading purposes.
Additionally, since oil and natural gas prices are inherently volatile, sustained lower commodity prices could result in impairment charges under our full cost ceiling test calculation. The ceiling test calculation dictates that we use the unweighted arithmetic average price of crude oil and natural gas as of the first day of each month for the 12-month
26
period ending at the balance sheet date. Using the crude oil price for July 2022 of $110.2 per barrel, and holding it constant for two months to create a trailing 12-month period of average prices that is more reflective of recent price trends, our ceiling test calculation would not have generated an impairment, holding all other inputs and factors constant. In addition to commodity prices, our production rates, levels of proved reserves, future development costs, transfers of unevaluated properties to our full cost pool, capital spending and other factors will determine our actual ceiling test calculation and impairment analyses in future periods.
Recent Developments
In May 2022, we entered into a joint venture agreement with Caracara Services, LLC (“Caracara”) to develop a strategic acid gas treatment and carbon sequestration facility (the “Facility”) in Winkler County, Texas. The joint venture, operating as Brazos Amine Treater, LLC (“BAT”), has also entered into a Gas Treating Agreement (“GTA”) with us for gas production from our Monument Draw area. In exchange for contributing to the joint venture a wellbore with an approved permit for the injection of acid gas and surface land, we retained a 5% equity interest in BAT, an unconsolidated subsidiary. Caracara is obligated to provide all necessary capital for the construction of the Facility, which is expected to come online on or before twelve months from the effective date of the GTA, with an initial capacity of approximately 30 MMcf per day, and a design capacity to treat up to 10% combined concentrations for H2S and CO2. Under the GTA, we will pay a treating rate that varies based on volumes delivered to the Facility for a term that will last 20 years from the in-service date of the Facility and have a minimum volume commitment of 20 MMcf per day, with certain rollover rights and start-up flexibility, for an initial term of five years from the in service date of the Facility, which can be extended up to seven years under certain conditions.
Capital Resources and Liquidity
Overview. At June 30, 2022, we had $43.6 million of cash and cash equivalents, $220.0 million of indebtedness outstanding, approximately $1.3 million letters of credit outstanding and $15.0 million in delayed draw term loans available to be drawn under our Term Loan Agreement, subject to the satisfaction of certain conditions defined in the agreement.
Capital Expenditures. During 2022, we expect to spend approximately $130.0 million to $150.0 million in capital expenditures, including drilling, completion, support infrastructure and other capital costs. Included in our remaining 2022 capital expenditures budget is approximately $4.7 million associated with an active drilling rig commitment through the fourth quarter of 2022. We also have a minimum volume commitment of approximately $3.3 million with a third party for the purchase of chemicals to treat sour gas production through December 31, 2022. Our capital spending requirements and commitments are expected to be funded with cash and cash equivalents on hand from the funding of our Term Loan Agreement (which is further described below) and cash flows from operations.
Debt Obligations. On November 24, 2021, we and our wholly owned subsidiary, Halcón Holdings, LLC (Borrower) entered into the Term Loan Agreement with Macquarie Bank Limited, as administrative agent, and certain other financial institutions party thereto, as lenders. The Term Loan Agreement amends and restates in its entirety our previous revolving credit agreement. Pursuant to the Term Loan Agreement, the lenders agreed to loan us (i) $200.0 million, which funded on November 24, 2021 and was partially used to refinance all amounts owed under the Senior Credit Agreement; (ii) up to $20.0 million under the first delayed draw of the Term Loan Agreement, which was drawn on April 29, 2022 and (iii) up to $15.0 million, which amount will be available to be drawn from the date certain wells included in the approved plan of development (APOD) are deemed producing APOD wells until up to 18 months after November 24, 2021, subject to the satisfaction of certain conditions. An additional $5.0 million is available for the issuance of letters of credit. The maturity date of the Term Loan Agreement is November 24, 2025. Until such maturity date, borrowings under the Term Loan Agreement shall bear interest at a rate per annum equal to LIBOR (or another applicable reference rate, as determined pursuant to the provisions of the Term Loan Agreement) plus an applicable margin of 7.00%.
We may be required to make mandatory prepayments of the loans under the Term Loan Agreement in connection with the incurrence of non-permitted debt, certain asset sales, or with cash on hand in excess of certain maximum levels beginning in 2023. For each fiscal quarter after January 1, 2023, we are required to make mandatory prepayments when
27
our Consolidated Cash Balance, as defined in the Term Loan Agreement, exceeds $20.0 million. Until December 31, 2024, the forecasted APOD capital expenditures for the succeeding fiscal quarter are excluded for purposes of determining the Consolidated Cash Balance. We are required to make scheduled amortization payments in the aggregate amount of $120.0 million from the fiscal quarter ending March 31, 2023 through the fiscal quarter ending September 30, 2025. Amounts outstanding under the Term Loan Agreement are guaranteed by certain of the Borrower’s direct and indirect subsidiaries and secured by a security interest in substantially all of the assets of the Borrower and such direct and indirect subsidiaries, and all of the equity interests of the Borrower held by us. As part of the Term Loan Agreement there are certain restrictions on the transfer of assets, including cash, to Battalion from the guarantor subsidiaries.
The Term Loan Agreement also contains certain financial covenants (as defined in the Term Loan Agreement), including the maintenance of the following ratios:
| ● | Asset Coverage Ratio of not less than 1.60 to 1.00 as of June 30, 2022, 1.70 to 1.00 as of September 30, 2022, and 1.80 to 1.00 as of December 31, 2022 and each fiscal quarter thereafter |
| ● | Total Net Leverage Ratio of not greater than 3.25 to 1.00 as of June 30, 2022, 3.00 to 1.00 as of September 30, 2022 and December 31, 2022, 2.75 to 1.00 as of March 31, 2023, and 2.50 to 1.00 as of each fiscal quarter thereafter, and |
| ● | Current Ratio of not less than 1.00 to 1.00, each determined as of the last day of any fiscal quarter period. |
As of June 30, 2022, the Company was in compliance with the financial covenants under the Term Loan Agreement.
The Term Loan Agreement also contains an APOD for our Monument Draw acreage through the drilling and completion of certain wells. The Term Loan Agreement contains a proved developed producing production test and an APOD economic test which we must maintain compliance with otherwise, subject to any available remedies or waivers, we are required to immediately cease making expenditures in respect of the approved plan of development other than any expenditures deemed necessary by us in respect of no more than six additional approved plan of development wells.
The Term Loan Agreement also contains certain events of default, including non-payment; breaches of representations and warranties; non-compliance with covenants or other agreements; cross-default to material indebtedness; judgments; change of control; and voluntary and involuntary bankruptcy.
Changes in the level and timing of our production, drilling and completion costs, the cost and availability of transportation for our production and other factors varying from our expectations can affect our ability to comply with the covenants under our Term Loan Agreement. As a consequence, we endeavor to anticipate potential covenant compliance issues and work with our lenders under our Term Loan Agreement to address any such issues ahead of time.
While we have been largely been successful in obtaining modifications of our covenants as needed (which last occurred in 2020 under our revolving credit facility which was replaced by our Term Loan Agreement in 2021), there can be no assurance that we will be successful in the future. In the event we are not successful in obtaining covenant modifications, if needed, there is no assurance that we will be successful in implementing alternatives that allow us to maintain compliance with our covenants or that we will be successful in obtaining alternative financing that provides us with the liquidity that we need to operate our business. Even if successful, alternative sources of financing could prove more expensive than borrowings under our Term Loan Agreement.
Other Risks and Uncertainties. Our future capital resources and liquidity depend, in part, on our success in developing our leasehold interests, growing our reserves and production and finding additional reserves. Cash is required to fund capital expenditures necessary to offset inherent declines in our production and proven reserves, which is typical in the capital-intensive oil and natural gas industry. We strive to maintain financial flexibility while pursuing our drilling plans and may access capital markets, pursue joint ventures, sell assets and engage in other transactions as necessary to, among other things, maintain sufficient liquidity, facilitate drilling on our undeveloped acreage position and permit us to selectively expand our acreage. Our ability to complete such transactions and maintain or increase our liquidity is subject to a number of variables, including our level of oil and natural gas production, proved reserves and commodity prices, the amount and cost of our indebtedness, as well as various economic and market conditions that have historically
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affected the oil and natural gas industry. Even if we are otherwise successful in growing our proved reserves and production, if oil and natural gas prices decline for a sustained period of time, our ability to fund our capital expenditures, complete acquisitions, reduce debt, meet our financial obligations and become profitable may be materially impacted.
In periods of increasing commodity prices, the Company also continues to be at risk to supply chain issues, including, but not limited to, labor shortages, pipe restrictions and potential delays in obtaining frac and/or drilling related equipment that could impact our business. During these periods, the costs and delivery times of rigs, equipment and supplies may also be substantially greater. The unavailability or high cost of drilling rigs and/or frac crews, pressure pumping equipment, tubulars and other supplies, and of qualified personnel can materially and adversely affect our operations and profitability.
We are also continuously monitoring the current and potential impacts of the novel coronavirus (COVID-19) pandemic on our business, including how it has and may continue to impact our operations, financial results, liquidity, contractors, customers, employees and vendors, and taking appropriate actions in response, including implementing various measures to ensure the continued operation of our business in a safe and secure manner.
During 2021, widespread availability of COVID-19 vaccines in the United States and elsewhere combined with accommodative governmental monetary and fiscal policies and other factors, led to a rebound in demand for oil and natural gas and increases in oil and natural gas prices. Further, in 2022, the effects of Russian sanctions amidst the conflict with Ukraine have pushed oil and gas prices higher. However, there remains the potential for demand for oil and natural gas to be adversely impacted by the economic effects of rising interest rates and tightening monetary policies, as well as the ongoing COVID-19 pandemic, including as a consequence of the circulation of more infectious “variants” of the disease, vaccine hesitancy, waning vaccine effectiveness or other factors. As a consequence, the Company is unable to predict whether oil and natural gas prices will remain at current levels or will be adversely impacted by these or other factors. For further information regarding risk factors which could impact the Company, see “Risk Factors” in Item 1A of the Company’s Annual Report on Form 10-K for the year ended December 31, 2021.
Actual or anticipated declines in domestic or foreign economic activity or growth rates, regional or worldwide increases in tariffs or other trade restrictions, turmoil affecting the U.S. or global financial system and markets and a severe economic contraction either regionally or worldwide, resulting from international conflicts, efforts to contain the COVID-19 coronavirus or other factors, could materially affect our business and financial condition and impact our ability to finance operations by worsening the actual or anticipated future drop in worldwide oil demand, negatively impacting the price received for oil and natural gas production or adversely impacting our ability to comply with covenants in our Term Loan Agreement. Negative economic conditions could also adversely affect the collectability of our trade receivables or performance by our vendors and suppliers or cause our commodity hedging arrangements to be ineffective if our counterparties are unable to perform their obligations. All of the foregoing may adversely affect our business, financial condition, results of operations, cash flows and, potentially, compliance with the covenants contained in our Term Loan Agreement.
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Cash Flow
Net increase (decrease) in cash and cash equivalents is summarized as follows (in thousands):
| | | | | | |
| | Six Months Ended | ||||
| | |||||
|
| 2022 | | 2021 | ||
| | | | | | |
Cash flows provided by (used in) operating activities | | $ | 28,333 | | $ | 29,100 |
Cash flows provided by (used in) investing activities | | | (51,986) | | | (36,669) |
Cash flows provided by (used in) financing activities | | | 19,069 | | | 4,732 |
Net increase (decrease) in cash, cash equivalents and restricted cash | | $ | (4,584) | | $ | (2,837) |
Operating Activities. Net cash flows provided by operating activities for the six months ended June 30, 2022 and 2021 were $28.3 million and $29.1 million, respectively. Operating cash flows for the six months ended June 30, 2022 decreased from the six months ended June 30, 2021 due primarily to realized losses from derivative contracts incurred in the six months ended June 30, 2022 as a result of increased commodity prices partially offset by higher total operating revenues due to an approximate $23.62 per Boe increase in average realized prices in the six months ended June 30, 2022.
Investing Activities. Net cash flows used in investing activities for the six months ended June 30, 2022 and 2021 were approximately $52.0 million and $36.7 million, respectively.
During the six months ended June 30, 2022, we spent $51.4 million on oil and natural gas capital expenditures, of which $45.7 million related to drilling and completion costs and $3.8 million related to the development of our treating equipment and gathering support infrastructure.
During the six months ended June 30, 2021, we spent $37.6 million on oil and natural gas capital expenditures, of which $33.0 million related to drilling and completion costs and $3.1 million related to the development of our treating equipment and gathering support infrastructure. We received $0.9 million in proceeds from the sale of oil and natural gas properties.
Financing Activities. Net cash flows provided by financing activities for the six months ended June 30, 2022 and 2021 were approximately $19.1 million and $4.7 million. During the six months ended June 30, 2022, we borrowed the $20 million available under the first delayed draw of the Term Loan Agreement. During the six months ended June 30, 2021, net borrowings of $5.0 million under our Senior Credit Agreement were used to partially fund our drilling and completions program and the development of our treating equipment and gathering support facilities.
Critical Accounting Policies and Estimates
Our discussion and analysis of our financial condition and results of operations are based upon the unaudited condensed consolidated financial statements, which have been prepared in accordance with accounting principles generally accepted in the United States. Preparation of these unaudited condensed consolidated financial statements requires us to make estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses. There have been no material changes to our critical accounting policies from those described in our Annual Report on Form 10-K for the fiscal year ended December 31, 2021.
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Results of Operations
Three Months Ended June 30, 2022 and 2021
We reported a net income (loss) of $13.0 million and $(33.9) million for the three months ended June 30, 2022 and 2021, respectively. The table included below sets forth financial information for the periods presented.
| | | | | | | | | |
| | Three Months Ended | | | | ||||
| | June 30, | | | | ||||
In thousands (except per unit and per Boe amounts) |
| 2022 | | 2021 | | Change | |||
Net income (loss) | | $ | 13,047 | | $ | (33,929) | | $ | 46,976 |
Operating revenues: | | | | | | | | | |
Oil | | | 73,944 | | | 51,935 | | | 22,009 |
Natural gas | | | 14,759 | | | 5,317 | | | 9,442 |
Natural gas liquids | | | 12,587 | | | 6,851 | | | 5,736 |
Other | | | 221 | | | 263 | | | (42) |
Operating expenses: | | | | | | | | | |
Production: | | | | | | | | | |
Lease operating | | | 11,909 | | | 10,169 | | | 1,740 |
Workover and other | | | 1,383 | | | 767 | | | 616 |
Taxes other than income | | | 5,372 | | | 2,912 | | | 2,460 |
Gathering and other | | | 15,869 | | | 14,331 | | | 1,538 |
General and administrative: | | | | | | | | | |
General and administrative | | | 4,115 | | | 3,546 | | | 569 |
Stock-based compensation | | | 473 | | | 485 | | | (12) |
Depletion, depreciation and accretion: | | | | | | | | | |
Depletion – Full cost | | | 12,414 | | | 11,015 | | | 1,399 |
Depreciation – Other | | | 76 | | | 105 | | | (29) |
Accretion expense | | | 111 | | | 129 | | | (18) |
Other income (expenses): | | | | | | | | | |
Net gain (loss) on derivative contracts | | | (31,910) | | | (53,089) | | | 21,179 |
Interest expense and other | | | (4,832) | | | (1,747) | | | (3,085) |
| | | | | | | | | |
Production: | | | | | | | | | |
Oil – MBbls | | | 674 | | | 805 | | | (131) |
Natural Gas - MMcf | | | 2,355 | | | 2,055 | | | 300 |
Natural gas liquids – MBbls | | | 303 | | | 270 | | | 33 |
Total MBoe(1) | | | 1,369 | | | 1,417 | | | (48) |
Average daily production – Boe/d(1) | | | 15,044 | | | 15,571 | | | (527) |
| | | | | | | | | |
Average price per unit (2): | | | | | | | | | |
Oil price - Bbl | | $ | 109.71 | | $ | 64.52 | | $ | 45.19 |
Natural gas price - Mcf | | | 6.27 | | | 2.59 | | | 3.68 |
Natural gas liquids price - Bbl | | | 41.54 | | | 25.37 | | | 16.17 |
Total per Boe(1) | | | 73.99 | | | 45.24 | | | 28.75 |
| | | | | | | | | |
Average cost per Boe: | | | | | | | | | |
Production: | | | | | | | | | |
Lease operating | | $ | 8.70 | | $ | 7.18 | | $ | 1.52 |
Workover and other | | | 1.01 | | | 0.54 | | | 0.47 |
Taxes other than income | | | 3.92 | | | 2.06 | | | 1.86 |
Gathering and other | | | 11.59 | | | 10.11 | | | 1.48 |
General and administrative: | | | | | | | | | |
General and administrative | | | 3.01 | | | 2.50 | | | 0.51 |
Stock-based compensation | | | 0.35 | | | 0.34 | | | 0.01 |
Depletion | | | 9.07 | | | 7.77 | | | 1.30 |
| (1) | Determined using a ratio of six Mcf of natural gas to one barrel of oil, condensate, or NGLs based on approximate energy equivalency. This is an energy content correlation and does not reflect the value or price relationship between the commodities. |
| (2) | Amounts exclude the impact of cash paid/received on settled contracts as we did not elect to apply hedge accounting. |
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Oil, natural gas and natural gas liquids revenues were $101.3 million and $64.1 million for the three months ended June 30, 2022 and 2021, respectively. The increase in revenues is primarily attributable to an approximate $28.75 per Boe increase in our average realized prices (excluding the effects of hedging arrangements). The amount we realize for our production depends predominantly upon commodity prices, which are affected by changes in market demand and supply, as impacted by overall economic activity, weather, transportation take-away capacity constraints, inventory storage levels, quality of production, basis differentials and other factors. For the three months ended June 30, 2022 and 2021, production averaged 15,044 Boe/d and 15,571 Boe/d, respectively.
Lease operating expenses were $11.9 million and $10.2 million for the three months ended June 30, 2022 and 2021, respectively. On a per unit basis, lease operating expenses were $8.70 per Boe and $7.18 per Boe for the three months ended June 30, 2022 and 2021, respectively. The increase in lease operating expenses in 2022 results primarily from a market increase in maintenance, power, and chemical costs..
Workover and other expenses were $1.4 million and $0.8 million for the three months ended June 30, 2022 and 2021, respectively. On a per unit basis, workover and other expenses were $1.01 per Boe and $0.54 per Boe for the three months ended June 30, 2022 and 2021, respectively. The increased workover and other expenses in 2022 relate to more significant workover projects undertaken in the current period.
Taxes other than income were $5.4 million and $2.9 million for the three months ended June 30, 2022 and 2021, respectively. Most production taxes are based on realized prices at the wellhead. As revenues or volumes from oil and natural gas sales increase or decrease, production taxes on these sales also increase or decrease. On a per unit basis, taxes other than income were $3.92 per Boe and $2.06 per Boe for the three months ended June 30, 2022 and 2021, respectively.
Gathering and other expenses were $15.9 million and $14.3 million for the three months ended June 30, 2022 and 2021, respectively. Gathering and other expenses include gathering fees paid to third parties on our oil and natural gas production and operating expenses of our gathering support infrastructure. Approximately $6.8 million and $4.6 million for the three months ended June 30, 2022 and 2021, respectively, relate to gathering and marketing fees paid to third parties on our oil and natural gas production. Gathering and marketing fees increased in 2022 as we marketed higher quantities of sour gas production to third parties in the current year period. Approximately $9.1 million and $9.7 million for the three months ended June 30, 2022 and 2021, respectively, relate to operating expenses on our treating equipment and gathering support facilities. The decrease in treating equipment and gathering support facilities expenses in 2022 results from lower operating expenses associated with our treating equipment.
General and administrative expense was $4.1 million and $3.5 million for the three months ended June 30, 2022 and 2021, respectively. The increase in general and administrative expense in the current period is primarily associated with an increase in professional fees partially offset by a decrease in corporate office lease expense, payroll and benefits costs. On a per unit basis, general and administrative expenses were $3.01 per Boe and $2.50 per Boe for the three months ended June 30, 2022 and 2021, respectively.
Depletion for oil and natural gas properties is calculated using the unit of production method, which depletes the capitalized costs of evaluated properties plus future development costs based on the ratio of production for the current period to total reserve volumes of evaluated properties as of the beginning of the period. Depletion expense was $12.4 million and $11.0 million for the three months ended June 30, 2022 and 2021, respectively. On a per unit basis, depletion expense was $9.07 per Boe and $7.77 per Boe for the three months ended June 30, 2022 and 2021, respectively. The increase in our depletion rate for the quarter ended June 30, 2022 compared to the same period in 2021 is primarily due to increased future development costs in 2022 compared to 2021 associated with PUD reserve additions during the periods
We enter into derivative commodity instruments to hedge our exposure to price fluctuations on our anticipated oil, natural gas and natural gas liquids production. Consistent with prior years, we have elected not to designate any positions as cash flow hedges for accounting purposes, and accordingly, we recorded the net change in the mark-to-market value of these derivative contracts in the unaudited condensed consolidated statements of operations. At June 30, 2022, we had a $10.1 million derivative asset, $6.1 million of which was classified as current, and we had a $149.9 million derivative liability, $91.8 million of which was classified as current. We recorded a net derivative loss of $31.9
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million ($12.8 million net unrealized gain and $44.7 million net realized loss on settled contracts) for the three months ended June 30, 2022. For the three months ended June 30, 2021, we recorded a net derivative loss of $53.1 million ($34.8 million net unrealized loss and $18.3 million net realized loss on settled and early terminated contracts).
Interest expense and other was $4.8 million and $1.7 million for the three months ended June 30, 2022 and 2021, respectively. Interest expense and other primarily increased in the current period due to higher debt balances in 2022, increased interest rates and amortization of debt issuance costs associated with our Term Loan Agreement entered into in 2022. This was partially offset by a $0.6 million change in the fair value of the Change of Control Call Option.
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Six Months Ended June 30, 2022 and 2021
We reported a net loss of $(79.7) million and $(67.3) million for the six months ended June 30, 2022 and 2021, respectively. The table included below sets forth financial information for the periods presented.
| | | | | | | | | |
| | Six Months Ended | | | | ||||
| | June 30, | | | | ||||
In thousands (except per unit and per Boe amounts) | | 2022 | | 2021 | | Change | |||
Net income (loss) | | $ | (79,697) | | $ | (67,304) | | $ | (12,393) |
Operating revenues: | | | | | | | | | |
Oil | | | 136,468 | | | 93,205 | | | 43,263 |
Natural gas | | | 23,640 | | | 14,404 | | | 9,236 |
Natural gas liquids | | | 22,590 | | | 11,760 | | | 10,830 |
Other | | | 415 | | | 515 | | | (100) |
Operating expenses: | | | | | | | | | |
Production: | | | | | | | | | |
Lease operating | | | 23,433 | | | 19,636 | | | 3,797 |
Workover and other | | | 2,248 | | | 1,327 | | | 921 |
Taxes other than income | | | 10,323 | | | 6,104 | | | 4,219 |
Gathering and other | | | 31,124 | | | 27,502 | | | 3,622 |
General and administrative: | | | | | | | | | |
General and administrative | | | 8,716 | | | 7,779 | | | 937 |
Stock-based compensation | | | 857 | | | 1,079 | | | (222) |
Depletion, depreciation and accretion: | | | | | | | | | |
Depletion – Full cost | | | 22,481 | | | 21,356 | | | 1,125 |
Depreciation – Other | | | 120 | | | 231 | | | (111) |
Accretion expense | | | 220 | | | 257 | | | (37) |
Other income (expenses): | | | | | | | | | |
Net gain (loss) on derivative contracts | | | (155,768) | | | (98,800) | | | (56,968) |
Interest expense and other | | | (7,520) | | | (3,117) | | | (4,403) |
| | | | | | | | | |
Production: | | | | | | | | | |
Oil – MBbls | | | 1,344 | | | 1,524 | | | (180) |
Natural Gas - MMcf | | | 4,670 | | | 4,188 | | | 482 |
Natural gas liquids – MBbls | | | 576 | | | 485 | | | 91 |
Total MBoe(1) | | | 2,698 | | | 2,707 | | | (9) |
Average daily production – Boe(1) | | | 14,906 | | | 14,956 | | | (50) |
| | | | | | | | | |
Average price per unit (2): | | | | | | | | | |
Oil price - Bbl | | $ | 101.54 | | $ | 61.16 | | $ | 40.38 |
Natural gas price - Mcf | | | 5.06 | | | 3.44 | | | 1.62 |
Natural gas liquids price - Bbl | | | 39.22 | | | 24.25 | | | 14.97 |
Total per Boe(1) | | | 67.72 | | | 44.10 | | | 23.62 |
| | | | | | | | | |
Average cost per Boe: | | | | | | | | | |
Production: | | | | | | | | | |
Lease operating | | $ | 8.69 | | $ | 7.25 | | $ | 1.44 |
Workover and other | | | 0.83 | | | 0.49 | | | 0.34 |
Taxes other than income | | | 3.83 | | | 2.25 | | | 1.58 |
Gathering and other | | | 11.54 | | | 10.16 | | | 1.38 |
General and administrative: | | | | | | | | | |
General and administrative | | | 3.23 | | | 2.87 | | | 0.36 |
Stock-based compensation | | | 0.32 | | | 0.40 | | | (0.08) |
Depletion | | | 8.33 | | | 7.89 | | | 0.44 |
| (1) | Natural gas reserves are converted to oil reserves using a ratio of six Mcf to one Bbl of oil. This ratio is based on energy equivalency, not price equivalency. The price for a barrel of oil equivalent for natural gas is substantially lower than the price for a barrel of oil. |
| (2) | Amounts exclude the impact of cash paid/received on settled contracts as we did not elect to apply hedge accounting. |
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Oil, natural gas and natural gas liquids revenues were $182.7 million and $119.4 million for the six months ended June 30, 2022 and 2021, respectively. The increase in revenues is primarily attributable to an approximate $23.62 per Boe increase in our average realized prices (excluding the effects of hedging arrangements). The amount we realize for our production depends predominantly upon commodity prices, which are affected by changes in market demand and supply, as impacted by overall economic activity, weather, transportation take-away capacity constraints, inventory storage levels, quality of production, basis differentials and other factors. For the six months ended June 30, 2022 and 2021, production averaged 14,906 Boe/d and 14,956 Boe/d, respectively. In February 2021, we temporarily shut-in production due to inclement weather. The estimated decrease in average daily oil and natural gas production associated with this temporary shut-in was approximately 600 Boe/d in the first six months of 2021. Current year production was impacted by natural production declines on our existing producing wells.
Lease operating expenses were $23.4 million and $19.6 million for the six months ended June 30, 2022 and 2021, respectively. On a per unit basis, lease operating expenses were $8.69 per Boe and $7.25 per Boe for the six months ended June 30, 2022 and 2021, respectively. The increase in lease operating expenses in 2022 results primarily from a market increase in maintenance, power, and chemical costs.
Workover and other expenses were $2.2 million and $1.3 million for the six months ended June 30, 2022 and 2021, respectively. On a per unit basis, workover and other expenses were $0.83 per Boe and $0.49 per Boe for the six months ended June 30, 2022 and 2021, respectively. The increased workover and other expenses in 2022 relate to more significant workover projects undertaken in the current period.
Taxes other than income were $10.3 million and $6.1 million for the six months ended June 30, 2022 and 2021, respectively. Most production taxes are based on realized prices at the wellhead. As revenues or volumes from oil and natural gas sales increase or decrease, production taxes on these sales also increase or decrease. On a per unit basis, taxes other than income were $3.83 per Boe and $2.25 per Boe for the six months ended June 30, 2022 and 2021, respectively.
Gathering and other expenses were $31.1 million and $27.5 million for the six months ended June 30, 2022 and 2021, respectively. Gathering and other expenses include gathering fees paid to third parties on our oil and natural gas production and operating expenses of our gathering support infrastructure. Approximately $13.4 million and $8.6 million for the six months ended June 30, 2022 and 2021, respectively, relate to gathering and marketing fees paid to third parties on our oil and natural gas production. Gathering and marketing fees increased in 2022 as we marketed higher quantities of sour gas production to third parties in the current year period. Approximately $17.8 million and $18.9 million for the six months ended June 30, 2022 and 2021, respectively, relate to operating expenses on our treating equipment and gathering support facilities. The decrease in treating equipment and gathering support facilities expenses in 2022 results from lower operating expenses associated with our treating equipment.
General and administrative expense was $8.7 million and $7.8 million for the six months ended June 30, 2022 and 2021, respectively. The increase in general and administrative expense in the current year period is primarily associated with an increase in professional fees and payroll and benefits. On a per unit basis, general and administrative expenses were $3.23 per Boe and $2.87 per Boe for the three months ended June 30, 2022 and 2021, respectively.
Depletion expense was $22.5 million and $21.4 million for the six months ended June 30, 2022 and 2021, respectively. Depletion for oil and natural gas properties is calculated using the unit of production method, which depletes the capitalized costs of evaluated properties plus future development costs based on the ratio of production for the current period to total reserve volumes of evaluated properties as of the beginning of the period. On a per unit basis, depletion expense was $8.33 per Boe and $7.89 per Boe for the six months ended June 30, 2022 and 2021, respectively. The increase in our depletion rate for the six months ended June 30, 2022 compared to the same period in 2021 is primarily due to increased future development costs in 2022 compared to 2021 associated with PUD reserve additions during the periods
We enter into derivative commodity instruments to economically hedge our exposure to price fluctuations on our anticipated oil, natural gas and natural gas liquids production. Consistent with prior years, we have elected not to designate any positions as cash flow hedges for accounting purposes, and accordingly, we recorded the net change in the mark-to-market value of these derivative contracts in the unaudited condensed consolidated statements of operations. At June 30, 2022, we had a $10.1 million derivative asset, $6.1 million of which was classified as current, and we had a
35
$149.9 million derivative liability, $91.8 million of which was classified as current. We recorded a net derivative loss of $155.8 million ($78.2 million net unrealized loss and $77.6 million net realized loss on settled and early terminated contracts) for the six months ended June 30, 2022. For the six months ended June 30, 2021, we recorded a net derivative loss of $98.8 million ($70.9 million net unrealized loss and $27.9 million net realized loss on settled and early terminated contracts).
Interest expense and other was $7.5 million and $3.1 million for the six months ended June 30, 2022 and 2021, respectively. Interest expense and other increased in the current period due primarily to higher debt balances in 2022, an increase in interest rates and amortization of debt issuance costs associated with our Term Loan Agreement entered in to in 2022. This was partially offset by a $2.6 million change in the fair value of the Change of Control Call Option.
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Derivative Instruments and Hedging Activity
We are exposed to various risks, including energy commodity price risk, such as price differentials between the NYMEX commodity price and the index price at the location where our production is sold. When oil and natural gas prices decline significantly, our ability to finance our capital budget and operations may be adversely impacted. We expect energy prices to remain volatile and unpredictable, therefore we have designed a risk management policy which provides for the use of derivative instruments to provide partial protection against declines in oil and natural gas prices by reducing the risk of price volatility and the affect it could have on our operations. The types of derivative instruments that we typically utilize include fixed-price swaps, costless collars, basis swaps and WTI NYMEX rolls. The total volumes that we hedge through the use of our derivative instruments varies from period to period; however, our requirement under our Term Loan Agreement is to hedge approximately 50% to 85% of our anticipated oil and natural gas production, in varying percentages by year, on a rolling basis for the next four years. Our hedge policies and objectives may change significantly as our operational profile and contractual obligations change but remain consistent with the requirements in effect under our Term Loan Agreement. We do not enter into derivative contracts for speculative trading purposes.
We are exposed to market risk on our open derivative contracts related to potential non-performance by our counterparties. It is our policy to enter into derivative contracts only with counterparties that are creditworthy institutions deemed by management as competitive market makers. As of June 30, 2022, we did not post collateral under any of our derivative contracts as they are secured under our Term Loan Agreement. We account for our derivative activities on the balance sheet as either an asset or liability measured at fair value. See Item 1. Condensed Consolidated Financial Statements (Unaudited)—Note 7, “Derivative and Hedging Activities,” for more details.
Fair Market Value of Financial Instruments
The estimated fair values for financial instruments are determined at discrete points in time based on relevant market information, involve uncertainties and cannot be determined with precision. The estimated fair value of cash, cash equivalents and restricted cash, accounts receivable and accounts payable approximates their carrying value due to their short-term nature. See Item 1. Condensed Consolidated Financial Statements (Unaudited)—Note 6, “Fair Value Measurements,” for additional information.
Interest Rate Sensitivity
We are also exposed to market risk related to adverse changes in interest rates. Our interest rate risk exposure results primarily from fluctuations in short-term rates, which are LIBOR based and may result in reductions of earnings or cash flows due to increases in the interest rates we pay on these obligations.
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At June 30, 2022, the principal amount of our debt was $220.0 million, which all bears interest at floating and variable interest rates that are tied to LIBOR. Fluctuations in market interest rates will cause our annual interest costs to fluctuate. At June 30, 2022, the weighted average interest rate on our variable rate debt was 9.25% per year. If the balance of our variable interest rate at June 30, 2022 were to remain constant, a 10% change in market interest rates would impact our cash flows by approximately $2.0 million per year.
ITEM 4. CONTROLS AND PROCEDURES
Under the supervision and with the participation of our management, including our Chief Executive Officer and our Chief Financial Officer, we evaluated the design and operation of our disclosure controls and procedures (as defined in rules 13a-15(e) and 15d-15(e) of the Securities Exchange Act of 1934, or the Exchange Act) as of June 30, 2022. On the basis of this review, our management, including our Chief Executive Officer and Chief Financial Officer, concluded that our disclosure controls and procedures are designed, and are effective, to give reasonable assurance that the information required to be disclosed by us in reports that we file under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the SEC and to ensure that information required to be disclosed in the reports filed or submitted under the Exchange Act is accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, in a manner that allows timely decisions regarding required disclosure.
We did not have any change in our internal controls over financial reporting during the three months ended June 30, 2022 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.
PART II. OTHER INFORMATION
ITEM 1. LEGAL PROCEEDINGS
Information regarding legal proceedings to which we are a party is set forth in Item 1. Condensed Consolidated Financial Statements (Unaudited)—Note 9, “Commitments and Contingencies,” which is incorporated herein by reference.
ITEM 1A. RISK FACTORS
There have been no changes to the risk factors described in our Annual Report on Form 10-K for the fiscal year ended December 31, 2021.
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ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS
The following table sets forth information regarding our acquisition of shares of common stock for the periods presented.
| | | | | | | | |
| Total Number of Shares Purchased(1) | | Average Price Paid Per Share | | Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs | | Maximum Number (or Approximate Dollar Value) of Shares that May Yet Be Purchased Under the Plans or Programs | |
April 2022 | 185 | | $ | 19.64 | | — | | — |
May 2022 | — | | | — | | — | | — |
June 2022 | 185 | | | 15.10 | | — | | — |
| (1) | All of the shares were surrendered by employees in exchange for the payment of tax withholding upon the vesting of restricted stock units. The acquisition of the surrendered shares was not part of a publicly announced program to repurchase shares of our common stock. |
ITEM 3. DEFAULTS UPON SENIOR SECURITIES
None.
ITEM 4. MINE SAFETY DISCLOSURES
Not applicable.
ITEM 5. OTHER INFORMATION
None.
ITEM 6. EXHIBITS
The following documents are included as exhibits to this Quarterly Report on Form 10-Q. Those exhibits incorporated by reference are so indicated by the information supplied with respect thereto. Those exhibits which are not incorporated by reference are attached hereto.
3.1 | ||
3.2 | | |
10.1 | | |
31.1* | | Sarbanes-Oxley Section 302 certification of Principal Executive Officer |
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31.2* | | Sarbanes-Oxley Section 302 certification of Principal Financial Officer |
32* | | |
101.INS* | | Inline XBRL Instance Document |
101.SCH* | | Inline XBRL Taxonomy Extension Schema Document |
101.CAL* | | Inline XBRL Taxonomy Extension Calculation Linkbase Document |
101.DEF* | | Inline XBRL Taxonomy Extension Definition Document |
101.LAB* | | Inline XBRL Taxonomy Extension Label Linkbase Document |
101.PRE* | | Inline XBRL Taxonomy Extension Presentation Linkbase Document |
104* | | Cover Page Interactive Data File (embedded within the Inline XBRL document) |
* | Attached hereto. |
† | Indicates management contract or compensatory plan or arrangement. |
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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.
| BATTALION OIL CORPORATION | ||
| | ||
| | ||
By: | |||
| | Name: | |
| | Title: | Chief Executive Officer |
| | | |
| | | |
By: | /s/ R. KEVIN ANDREWS | ||
| | Name: | |
| | Title: | Executive Vice President, Chief Financial Officer and Treasurer |
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| This ‘10-Q’ Filing | Date | Other Filings | ||
|---|---|---|---|---|
 | ||||
| 11/24/25 | ||||
| 9/30/25 | ||||
| 12/31/24 | ||||
| 3/31/23 | ||||
| 1/1/23 | ||||
| 12/31/22 | ||||
| 10/8/22 | ||||
| 9/30/22 | ||||
| Filed on: | 8/8/22 | 8-K | ||
| 8/4/22 | ||||
| For Period end: | 6/30/22 | |||
| 4/29/22 | ||||
| 3/31/22 | 10-Q | |||
| 3/7/22 | 10-K, 8-K | |||
| 12/31/21 | 10-K | |||
| 11/24/21 | 8-K | |||
| 9/30/21 | 10-Q, 8-K | |||
| 8/13/21 | ||||
| 6/30/21 | 10-Q | |||
| 3/31/21 | 10-Q | |||
| 12/31/20 | 10-K | |||
| 10/8/19 | 3, 4, 8-K, 8-K/A, D, D/A | |||
| List all Filings | ||||
As Of Filer Filing For·On·As Docs:Size Issuer Filing Agent 11/29/21 Battalion Oil Corp. 8-K:1,9 11/24/21 12:1.7M Toppan Merrill Bridge/FA 3/25/20 Battalion Oil Corp. 10-K 12/31/19 109:20M Toppan Merrill Bridge/FA 1/27/20 Battalion Oil Corp. 8-K:5,7,9 1/21/20 4:149K Toppan Merrill/FA |