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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
(X) Quarterly Report Pursuant to Section 13 or 15(d)
of the Securities Exchange Act of 1934
For the quarterly period ended September 30, 2020
Commission File Number 1-8754
SILVERBOW RESOURCES, INC.
(Exact Name of Registrant as Specified in Its Charter)
| Delaware | 20-3940661 | ||||
|
(State of Incorporation)
|
(I.R.S. Employer Identification No.)
|
||||
575 North Dairy Ashford, Suite 1200
Houston, Texas 77079
(281) 874-2700
(Address and telephone number of principal executive offices)
Securities registered pursuant to Section 12(b) of the Act:
| Title of each class | Trading Symbol(s) | Name of each exchange on which registered | ||||||
| Common Stock, par value $0.01 per share | SBOW | New York Stock Exchange | ||||||
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.
| Yes | þ | No | o | ||||||||
Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files).
| Yes | þ | No |
o
|
||||||||
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 definition of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.
| Large Accelerated Filer | o | Accelerated Filer |
þ
|
Non-Accelerated Filer |
o
|
Smaller Reporting Company |
þ
|
|||||||||||||||||||||||||
| Emerging Growth Company | o | |||||||||||||||||||||||||||||||
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 revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act.
| o | ||
1
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).
| Yes | o | No | þ | ||||||||
Indicate by check mark whether the registrant has filed all documents and reports required to be filed by Sections 12, 13 or 15(d) of the Securities Exchange Act of 1934 subsequent to the distribution of securities under a plan confirmed by a court.
| Yes | þ | No |
o
|
||||||||
Indicate the number of shares outstanding of each of the issuer’s classes
of common stock, as of the latest practicable date.
| Common Stock ($.01 Par Value) (Class of Stock) | 11,936,679 Shares outstanding at October 28, 2020 | ||||
2
SILVERBOW RESOURCES, INC.
FORM 10-Q
FOR THE QUARTERLY PERIOD ENDED SEPTEMBER 30, 2020
INDEX
| Page | ||||||||
| Part I | FINANCIAL INFORMATION | |||||||
| Item 1. | Condensed Consolidated Financial Statements | |||||||
| Item 2. | ||||||||
| Item 3. | ||||||||
| Item 4. | ||||||||
| Part II | OTHER INFORMATION | |||||||
| Item 1. | ||||||||
| Item 1A. | ||||||||
| Item 2. | ||||||||
| Item 3. | ||||||||
| Item 4. | ||||||||
| Item 5. | ||||||||
| Item 6. | ||||||||
3
PART I. FINANCIAL INFORMATION
Condensed Consolidated Balance Sheets (Unaudited)
SilverBow Resources, Inc. and Subsidiary (in thousands, except share amounts)
4
Condensed Consolidated Statements of Operations (Unaudited)
SilverBow Resources, Inc. and Subsidiary (in thousands, except per-share amounts)
| Three Months Ended September 30, 2020 | Three Months Ended September 30, 2019 | ||||||||||
| Revenues: | |||||||||||
| Oil and gas sales | $ | 45,699 | $ | 72,014 | |||||||
| Operating Expenses: | |||||||||||
| General and administrative, net | 5,833 | 6,247 | |||||||||
| Depreciation, depletion, and amortization | 13,975 | 24,937 | |||||||||
| Accretion of asset retirement obligations | 90 | 88 | |||||||||
| Lease operating costs | 5,211 | 5,507 | |||||||||
| Workovers | 8 | 93 | |||||||||
| Transportation and gas processing | 5,094 | 6,782 | |||||||||
| Severance and other taxes | 2,512 | 3,778 | |||||||||
| Total Operating Expenses | 32,723 | 47,432 | |||||||||
| Operating Income (Loss) | 12,976 | 24,582 | |||||||||
| Non-Operating Income (Expense) | |||||||||||
| Gain (loss) on commodity derivatives, net | (12,944) | 13,409 | |||||||||
| Interest expense, net | (7,444) | (9,435) | |||||||||
| Other income (expense), net | (56) | 134 | |||||||||
| Income (Loss) Before Income Taxes | (7,468) | 28,690 | |||||||||
| Provision (Benefit) for Income Taxes | (572) | 1,039 | |||||||||
| Net Income (Loss) | $ | (6,896) | $ | 27,651 | |||||||
| Per Share Amounts | |||||||||||
| Basic: Net Income (Loss) | $ | (0.58) | $ | 2.35 | |||||||
| Diluted: Net Income (Loss) | $ | (0.58) | $ | 2.35 | |||||||
| Weighted-Average Shares Outstanding - Basic | 11,935 | 11,762 | |||||||||
| Weighted-Average Shares Outstanding - Diluted | 11,935 | 11,780 | |||||||||
| See accompanying Notes to Condensed Consolidated Financial Statements. | |||||||||||
5
Condensed Consolidated Statements of Operations (Unaudited)
SilverBow Resources, Inc. and Subsidiary (in thousands, except per-share amounts)
| Nine Months Ended September 30, 2020 | Nine Months Ended September 30, 2019 | ||||||||||
| Revenues: | |||||||||||
| Oil and gas sales | $ | 123,921 | $ | 218,781 | |||||||
| Operating Expenses: | |||||||||||
| General and administrative, net | 17,926 | 19,146 | |||||||||
| Depreciation, depletion, and amortization | 51,130 | 70,771 | |||||||||
| Accretion of asset retirement obligations | 263 | 257 | |||||||||
| Lease operating costs | 16,023 | 15,074 | |||||||||
| Workovers | 8 | 613 | |||||||||
| Transportation and gas processing | 16,291 | 19,917 | |||||||||
| Severance and other taxes | 7,513 | 11,044 | |||||||||
| Write-down of oil and gas properties | 355,948 | — | |||||||||
| Total Operating Expenses | 465,102 | 136,822 | |||||||||
| Operating Income (Loss) | (341,181) | 81,959 | |||||||||
| Non-Operating Income (Expense) | |||||||||||
| Gain (loss) on commodity derivatives, net | 66,884 | 34,312 | |||||||||
| Interest expense, net | (23,876) | (27,500) | |||||||||
| Other income (expense), net | 50 | 173 | |||||||||
| Income (Loss) Before Income Taxes | (298,123) | 88,944 | |||||||||
| Provision (Benefit) for Income Taxes | 20,607 | (19,464) | |||||||||
| Net Income (Loss) | $ | (318,730) | $ | 108,408 | |||||||
| Per Share Amounts | |||||||||||
| Basic: Net Income (Loss) | $ | (26.81) | $ | 9.24 | |||||||
| Diluted: Net Income (Loss) | $ | (26.81) | $ | 9.21 | |||||||
| Weighted-Average Shares Outstanding - Basic | 11,890 | 11,739 | |||||||||
| Weighted-Average Shares Outstanding - Diluted | 11,890 | 11,776 | |||||||||
| See accompanying Notes to Condensed Consolidated Financial Statements. | |||||||||||
6
Condensed Consolidated Statements of Stockholders’ Equity (Unaudited)
SilverBow Resources, Inc. and Subsidiary (in thousands, except share amounts)
| Common Stock | Additional Paid-In Capital | Treasury Stock | Retained Earnings (Accumulated Deficit) | Total | |||||||||||||||||||||||||
| Balance, December 31, 2018 | $ | 118 | $ | 286,281 | $ | (1,870) | $ | (9,702) | $ | 274,827 | |||||||||||||||||||
| Purchase of treasury shares (11,076 shares) | — | — | (260) | — | (260) | ||||||||||||||||||||||||
| Issuance of restricted stock (61,263 shares) | — | — | — | — | — | ||||||||||||||||||||||||
| Share-based compensation | — | 1,849 | — | — | 1,849 | ||||||||||||||||||||||||
| Net Income | — | — | — | 16,053 | 16,053 | ||||||||||||||||||||||||
| Balance, March 31, 2019 | $ | 118 | $ | 288,130 | $ | (2,130) | $ | 6,351 | $ | 292,469 | |||||||||||||||||||
| Purchase of treasury shares (3,877 shares) | — | — | (58) | — | (58) | ||||||||||||||||||||||||
| Issuance of restricted stock (19,162 shares) | — | — | — | — | — | ||||||||||||||||||||||||
| Share-based compensation | — | 1,769 | — | — | 1,769 | ||||||||||||||||||||||||
| Net Income | — | — | — | 64,704 | 64,704 | ||||||||||||||||||||||||
| Balance, June 30, 2019 | $ | 118 | $ | 289,899 | $ | (2,188) | $ | 71,055 | $ | 358,884 | |||||||||||||||||||
| Purchase of treasury shares (411 shares) | — | — | (5) | — | (5) | ||||||||||||||||||||||||
| Issuance of restricted stock (26,684 shares) | 1 | — | — | — | 1 | ||||||||||||||||||||||||
| Share-based compensation | — | 1,855 | — | — | 1,855 | ||||||||||||||||||||||||
| Net Income | — | — | — | 27,651 | 27,651 | ||||||||||||||||||||||||
| Balance, September 30, 2019 | $ | 119 | $ | 291,754 | $ | (2,193) | $ | 98,706 | $ | 388,386 | |||||||||||||||||||
| Balance, December 31, 2019 | $ | 119 | $ | 292,916 | $ | (2,282) | $ | 104,954 | $ | 395,707 | |||||||||||||||||||
| Purchase of treasury shares (26,675 shares) | — | — | (83) | — | (83) | ||||||||||||||||||||||||
| Issuance of restricted stock (105,108 shares) | 1 | (1) | — | — | — | ||||||||||||||||||||||||
| Share-based compensation | — | 1,335 | — | — | 1,335 | ||||||||||||||||||||||||
| Net Loss | — | — | — | (5,858) | (5,858) | ||||||||||||||||||||||||
| Balance, March 31, 2020 | $ | 120 | $ | 294,250 | $ | (2,365) | $ | 99,096 | $ | 391,101 | |||||||||||||||||||
| Shares issued from warrant exercise (5 shares) | — | — | — | — | — | ||||||||||||||||||||||||
| Purchase of treasury shares (1,098 shares) | — | — | (3) | — | (3) | ||||||||||||||||||||||||
| Issuance of restricted stock (49,665 shares) | — | — | — | — | — | ||||||||||||||||||||||||
| Share-based compensation | — | 1,229 | — | — | 1,229 | ||||||||||||||||||||||||
| Net Loss | — | — | — | (305,976) | (305,976) | ||||||||||||||||||||||||
| Balance, June 30, 2020 | $ | 120 | $ | 295,479 | $ | (2,368) | $ | (206,880) | $ | 86,351 | |||||||||||||||||||
| Purchase of treasury shares (958 shares) | — | — | (4) | — | (4) | ||||||||||||||||||||||||
| Issuance of restricted stock (3,953 shares) | 1 | — | — | — | 1 | ||||||||||||||||||||||||
| Share-based compensation | — | 1,150 | — | — | 1,150 | ||||||||||||||||||||||||
| Net Loss | — | — | — | (6,896) | (6,896) | ||||||||||||||||||||||||
| Balance, September 30, 2020 | $ | 121 | $ | 296,629 | $ | (2,372) | $ | (213,776) | $ | 80,602 | |||||||||||||||||||
| See accompanying Notes to Condensed Consolidated Financial Statements. | |||||||||||||||||||||||||||||
7
Condensed Consolidated Statements of Cash Flows (Unaudited)
SilverBow Resources, Inc. and Subsidiary (in thousands)
| Nine Months Ended September 30, 2020 | Nine Months Ended September 30, 2019 | ||||||||||
| Cash Flows from Operating Activities: | |||||||||||
| Net income (loss) | $ | (318,730) | $ | 108,408 | |||||||
| Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities | |||||||||||
| Depreciation, depletion, and amortization | 51,130 | 70,771 | |||||||||
| Write-down of oil and gas properties | 355,948 | — | |||||||||
| Accretion of asset retirement obligations | 263 | 257 | |||||||||
| Deferred income taxes | 21,087 | (19,735) | |||||||||
| Share-based compensation | 3,503 | 5,091 | |||||||||
| (Gain) Loss on derivatives, net | (66,884) | (34,312) | |||||||||
| Cash settlement (paid) received on derivatives | 76,150 | 16,087 | |||||||||
| Settlements of asset retirement obligations | (27) | (67) | |||||||||
| Write down of debt issuance cost | 459 | — | |||||||||
| Other | 2,436 | 1,782 | |||||||||
| Change in operating assets and liabilities | |||||||||||
| (Increase) decrease in accounts receivable and other current assets | 7,413 | 13,746 | |||||||||
| Increase (decrease) in accounts payable and accrued liabilities | (3,981) | (8,824) | |||||||||
| Increase (decrease) in income taxes payable | (480) | 217 | |||||||||
| Increase (decrease) in accrued interest | (505) | (356) | |||||||||
| Net Cash Provided by (Used in) Operating Activities | 127,782 | 153,065 | |||||||||
| Cash Flows from Investing Activities: | |||||||||||
| Additions to property and equipment | (102,713) | (234,859) | |||||||||
| Acquisition of oil and gas properties | (3,441) | — | |||||||||
| Proceeds from the sale of property and equipment | 4,752 | (96) | |||||||||
| Payments on property sale obligations | (426) | (4,402) | |||||||||
| Net Cash Provided by (Used in) Investing Activities | (101,828) | (239,357) | |||||||||
| Cash Flows from Financing Activities: | |||||||||||
| Proceeds from bank borrowings | 71,000 | 315,000 | |||||||||
| Payments of bank borrowings | (97,000) | (228,000) | |||||||||
| Purchase of treasury shares | (90) | (323) | |||||||||
| Net Cash Provided by (Used in) Financing Activities | (26,090) | 86,677 | |||||||||
| Net Increase (Decrease) in Cash and Cash Equivalents | (136) | 385 | |||||||||
| Cash and Cash Equivalents at Beginning of Period | 1,358 | 2,465 | |||||||||
| Cash and Cash Equivalents at End of Period | $ | 1,222 | $ | 2,850 | |||||||
| Supplemental Disclosures of Cash Flow Information: | |||||||||||
| Cash paid during period for interest, net of amounts capitalized | $ | 22,290 | $ | 26,172 | |||||||
| Changes in capital accounts payable and capital accruals | $ | (25,641) | $ | (27,905) | |||||||
| See accompanying Notes to Condensed Consolidated Financial Statements. | |||||||||||
8
Notes to Condensed Consolidated Financial Statements (Unaudited)
SilverBow Resources, Inc. and Subsidiary
(1) General Information
SilverBow Resources, Inc. (“SilverBow,” the “Company,” or “we”) is an independent oil and gas company headquartered in Houston, Texas. The Company's strategy is focused on acquiring and developing assets in the Eagle Ford Shale located in South Texas. Being a committed and long-term operator in South Texas, the Company possesses a significant understanding of the reservoirs in the region. We leverage this competitive understanding to assemble high quality drilling inventory while continuously enhancing our operations to maximize returns on capital invested.
The condensed consolidated financial statements included herein are unaudited and certain information and note disclosures normally included in financial statements prepared in accordance with accounting principles generally accepted in the United States (“GAAP”) have been omitted pursuant to the rules and regulations of the Securities and Exchange Commission. We believe that the disclosures presented are adequate to allow the information presented not to be misleading. The condensed consolidated financial statements should be read in conjunction with the audited financial statements and the notes thereto included in our Annual Report on Form 10-K for the fiscal year ended December 31, 2019.
As further discussed in Note 2, the impact of the Coronavirus Disease 2019 (“COVID-19”) pandemic and related economic, business and market disruptions continue to evolve and its future effects are uncertain. The actual impact of these recent developments on the Company will depend on numerous factors, many of which are beyond management's control and knowledge. It is therefore difficult for management to assess or predict with precision the broad future effect of this health crisis on the global economy, the energy industry or the Company. As additional information becomes available, events or circumstances change and strategic operational decisions are made by management, adjustments may be required which could have a material adverse impact on the Company's consolidated financial position, results of operations and cash flows.
(2) Summary of Significant Accounting Policies
Basis of Presentation. The consolidated financial statements included herein reflect necessary adjustments, all of which were of a recurring nature unless otherwise disclosed herein, and are in the opinion of our management necessary for a fair presentation.
Principles of Consolidation. The accompanying condensed consolidated financial statements include the accounts of SilverBow and its wholly owned subsidiary, SilverBow Resources Operating LLC, which are engaged in the exploration, development, acquisition, and operation of oil and gas properties, with a focus on oil and natural gas reserves in the Eagle Ford trend in Texas. Our undivided interests in oil and gas properties are accounted for using the proportionate consolidation method, whereby our proportionate share of the assets, liabilities, revenues, and expenses are included in the appropriate classifications in the accompanying condensed consolidated financial statements. Intercompany balances and transactions have been eliminated in preparing the accompanying condensed consolidated financial statements.
COVID-19. In March and April 2020, the COVID-19 pandemic caused volatility in the market price for crude oil due to the disruption of global supply and demand. In March, the spot price of West Texas Intermediate (“WTI”) crude oil declined over 50% in response to reductions in global demand due to the COVID-19 pandemic and announcements by Saudi Arabia and Russia of plans to increase crude oil production. Following this unprecedented collapse in crude oil prices, the spot price of Brent and WTI crude oil closed at approximately $15 and $21 per barrel, respectively, on March 31, 2020.
In April 2020, WTI oil prices declined further to approximately $10 per barrel for May 2020 delivery. Crude oil prices fell further in April but partially recovered during the second quarter of 2020 with Brent and WTI crude oil closing at approximately $41 and $39 per barrel, respectively, on June 30, 2020. Crude oil prices traded slightly higher in the third quarter of 2020 with Brent and WTI crude closing at approximately $42 and $40 per barrel, on September 30, 2020.
In response to these market conditions, including the COVID-19 pandemic and the decline in oil prices and economic outlook, the Company released its sole drilling rig in April 2020 and deferred the completion and placement on production of eight wells until the second half of 2020. In the third quarter of 2020, the Company restarted completions activity and returned to sales all previously curtailed oil volumes and a substantial portion of natural gas volumes. Approximately 20 million cubic feet per day (“MMcf/d”) of net gas production remained shut-in at quarter-end. The Company began returning these volumes to production in late October 2020 to align with favorable natural gas prices.
9
The full impact of the COVID-19 pandemic continues to evolve as of the date of this report. As such, the full magnitude that the pandemic will have on the Company’s financial condition, liquidity, and future results of operations is uncertain. Management is actively monitoring the impact of the COVID-19 pandemic on the Company's financial condition, liquidity, operations, suppliers, industry and workforce.
In addition, if the depressed pricing environment continues for an extended period, it may in the future lead to (i) a further reduction in oil and natural gas reserves, including the possible further removal of proved undeveloped reserves (ii) further impairment of proved and/or unproved oil and natural gas properties and a potential increase in depletion expense and (iii) reductions in the borrowing base under the Credit Agreement as discussed in Note 6.
If the pandemic and low oil price environment continues, it may have a material adverse effect on the Company’s operating cash flows, liquidity, and future development plans.
Subsequent Events. We have evaluated subsequent events requiring potential accrual or disclosure in our condensed consolidated financial statements. Effective November 2, 2020, as part of our regularly scheduled borrowing base redetermination, the borrowing base of our Credit Facility (as defined below) was decreased from $330 million to $310 million. See Note 6 for more information.
Through October 31, 2020, the Company entered into additional derivative contracts. The following tables summarize the weighted-average prices as well as future production volumes for our future derivative contracts entered into after September 30, 2020:
|
Oil Derivative Contracts
(New York Mercantile Exchange (“NYMEX”) West Texas Intermediate (“WTI”) Settlements) |
Total Volumes
(Bbls)(1)
|
Weighted-Average Price | Weighted-Average Collar Floor Price | Weighted-Average Collar Call Price | |||||||||||||||||||
| 2022 Contracts | |||||||||||||||||||||||
| Swap Contracts | |||||||||||||||||||||||
| 3Q22 | 36,800 | $ | 43.38 | ||||||||||||||||||||
| Collar Contracts | |||||||||||||||||||||||
| 1Q22 | 40,500 | $ | 40.00 | $ | 45.55 | ||||||||||||||||||
| 2Q22 | 29,400 | $ | 40.00 | $ | 45.30 | ||||||||||||||||||
(1) Bbl refers to one barrel of oil.
|
Natural Gas Derivative Contracts
(NYMEX Henry Hub Settlements) |
Total Volumes
(MMBtu) |
Weighted-Average Collar Floor Price | Weighted-Average Collar Call Price | ||||||||||||||
| 2022 Contracts | |||||||||||||||||
| Collar Contracts | |||||||||||||||||
| 3Q22 | 920,000 | $ | 2.35 | $ | 2.65 | ||||||||||||
|
Natural Gas Basis Derivative Swaps
(East Texas Houston Ship Channel vs. NYMEX Settlements) |
Total Volumes
(MMBtu) |
Weighted-Average Price | |||||||||
| 2022 Contracts | |||||||||||
| 1Q22 | 1,800,000 | $ | (0.08) | ||||||||
| 2Q22 | 1,820,000 | $ | (0.08) | ||||||||
| 3Q22 | 1,840,000 | $ | (0.08) | ||||||||
| 4Q22 | 1,840,000 | $ | (0.08) | ||||||||
There were no other material subsequent events requiring additional disclosure in these condensed consolidated financial statements.
Use of Estimates. The preparation of financial statements in conformity with GAAP requires us to make estimates and assumptions that affect the reported amounts of certain assets and liabilities and the reported amounts of certain revenues and expenses during each reporting period. Such estimates and assumptions are subject to a number of risks and uncertainties that
10
may cause actual results to differ materially from such estimates. Significant estimates and assumptions underlying these financial statements include:
•the estimated quantities of proved oil and natural gas reserves used to compute depletion of oil and natural gas properties, the related present value of estimated future net cash flows therefrom, and the Ceiling Test impairment calculation,
•estimates related to the collectability of accounts receivable and the credit worthiness of our customers,
•estimates of the counterparty bank risk related to letters of credit that our customers may have issued on our behalf,
•estimates of future costs to develop and produce reserves,
•accruals related to oil and gas sales, capital expenditures and lease operating expenses ("LOE"),
•estimates in the calculation of share-based compensation expense,
•estimates of our ownership in properties prior to final division of interest determination,
•the estimated future cost and timing of asset retirement obligations,
•estimates made in our income tax calculations, including the valuation of our deferred tax assets,
•estimates in the calculation of the fair value of commodity derivative assets and liabilities,
•estimates in the assessment of current litigation claims against the Company,
•estimates in amounts due with respect to open state regulatory audits, and
•estimates on future lease obligations.
While we are not currently aware of any material revisions to any of our estimates, there will likely be future revisions to our estimates resulting from matters such as new accounting pronouncements, changes in ownership interests, payouts, joint venture audits, reallocations by purchasers or pipelines, or other corrections and adjustments common in the oil and gas industry, many of which relate to prior periods. These types of adjustments cannot be currently estimated and are expected to be recorded in the period during which the adjustments are known.
We are subject to legal proceedings, claims, liabilities and environmental matters that arise in the ordinary course of business. We accrue for losses when such losses are considered probable and the amounts can be reasonably estimated.
Property and Equipment. We follow the “full-cost” method of accounting for oil and natural gas property and equipment costs. Under this method of accounting, all productive and nonproductive costs incurred in the exploration, development, and acquisition of oil and natural gas reserves are capitalized. Such costs may be incurred both prior to and after the acquisition of a property and include lease acquisitions, geological and geophysical services, drilling, completion, and equipment. Internal costs incurred that are directly identified with exploration, development, and acquisition activities undertaken by us for our own account, and which are not related to production, general corporate overhead, or similar activities, are also capitalized. For the three months ended September 30, 2020 and 2019, such internal costs when capitalized totaled $0.8 million and $1.2 million, respectively. For the nine months ended September 30, 2020 and 2019, such internal costs capitalized totaled $2.8 million and $4.1 million, respectively. Interest costs are also capitalized to unproved oil and natural gas properties (refer to Note 6 of these Notes to Condensed Consolidated Financial Statements for further discussion on capitalized interest costs).
The “Property and Equipment” balances on the accompanying condensed consolidated balance sheets are summarized for presentation purposes. The following is a detailed breakout of our “Property and Equipment” balances (in thousands):
| September 30, 2020 | December 31, 2019 | ||||||||||
| Property and Equipment | |||||||||||
| Proved oil and gas properties | $ | 1,287,962 | $ | 1,201,296 | |||||||
| Unproved oil and gas properties | 30,661 | 41,201 | |||||||||
| Furniture, fixtures and other equipment | 5,166 | 5,220 | |||||||||
| Less – Accumulated depreciation, depletion, amortization & impairment | (787,830) | (380,728) | |||||||||
| Property and Equipment, Net | $ | 535,959 | $ | 866,989 | |||||||
No gains or losses are recognized upon the sale or disposition of oil and natural gas properties, except in transactions involving a significant amount of reserves or where the proceeds from the sale of oil and natural gas properties would
11
significantly alter the relationship between capitalized costs and proved reserves of oil and natural gas attributable to a cost center. Internal costs associated with selling properties are expensed as incurred.
We compute the provision for depreciation, depletion and amortization (“DD&A”) of oil and natural gas properties using the unit-of-production method. Under this method, we compute the provision by multiplying the total unamortized costs of oil and natural gas properties, including future development costs, gas processing facilities, and both capitalized asset retirement obligations and undiscounted abandonment costs of wells to be drilled, net of salvage values, but excluding costs of unproved properties, by an overall rate determined by dividing the physical units of oil and natural gas produced (which excludes natural gas consumed in operations) during the period by the total estimated units of proved oil and natural gas reserves (which excludes natural gas consumed in operations) at the beginning of the period. Future development costs are estimated on a property-by-property basis based on current economic conditions. The period over which we will amortize these properties is dependent on our production from these properties in future years. Furniture, fixtures and other equipment are recorded at cost and are depreciated by the straight-line method at rates based on the estimated useful lives of the property, which range between two and 20 years. Repairs and maintenance are charged to expense as incurred.
Geological and geophysical (“G&G”) costs incurred on developed properties are recorded in “Proved oil and gas properties” and therefore subject to amortization. G&G costs incurred that are associated with unproved properties are capitalized in “Unproved oil and gas properties” and evaluated as part of the total capitalized costs associated with a prospect. The cost of unproved properties not being amortized is assessed quarterly, on a property-by-property basis, to determine whether such properties have been impaired. In determining whether such costs should be impaired, we evaluate current drilling results, lease expiration dates, current oil and gas industry conditions, economic conditions, capital availability and available geological and geophysical information. Any impairment assessed is added to the cost of proved properties being amortized.
Full-Cost Ceiling Test. At the end of each quarterly reporting period, the unamortized cost of oil and natural gas properties (including natural gas processing facilities, capitalized asset retirement obligations, net of related salvage values and deferred income taxes) is limited to the sum of the estimated future net revenues from proved properties (excluding cash outflows from recognized asset retirement obligations, including future development and abandonment costs of wells to be drilled, using the preceding 12-months’ average price based on closing prices on the first day of each month, adjusted for price differentials, discounted at 10% and the lower of cost or fair value of unproved properties) adjusted for related income tax effects (“Ceiling Test”).
The quarterly calculations of the Ceiling Test and provision for DD&A are based on estimates of proved reserves. There are numerous uncertainties inherent in estimating quantities of proved reserves and in projecting the future rates of production, timing and plan of development. The accuracy of any reserves estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. Results of drilling, testing, and production subsequent to the date of the estimate may justify revision of such estimates. Accordingly, reserves estimates are often different from the quantities of oil and natural gas that are ultimately recovered.
Due to the effects of pricing and timing of projects we reported a non-cash impairment write-down, on a pre-tax basis, of $355.9 million for the nine months ended September 30, 2020 on our oil and natural gas properties. There was no impairment for the three months ended September 30, 2020 and no impairment for the three and nine months ended September 30, 2019.
If future capital expenditures outpace future discounted net cash flows in our reserve calculations, if we have significant declines in our oil and natural gas reserves volumes (which also reduces our estimate of discounted future net cash flows from proved oil and natural gas reserves) or if oil or natural gas prices decline, it is possible that non-cash write-downs of our oil and natural gas properties will occur again in the future. We cannot control and cannot predict what future prices for oil and natural gas will be; therefore, we cannot estimate the amount of any potential future non-cash write-down of our oil and natural gas properties due to decreases in oil or natural gas prices. However, it is reasonably possible that we will record additional Ceiling Test write-downs in future periods.
Accounts Receivable, Net. We assess the collectability of accounts receivable, and based on our judgment, we accrue a reserve when we believe a receivable may not be collected. At both September 30, 2020 and December 31, 2019, we had an allowance for doubtful accounts of less than $0.1 million. The allowance for doubtful accounts has been deducted from the total “Accounts receivable, net” balance on the accompanying condensed consolidated balance sheets.
At September 30, 2020, our “Accounts receivable, net” balance included $17.8 million for oil and gas sales, $0.5 million due from joint interest owners, $6.4 million for severance tax credit receivables and $4.2 million for other receivables.
12
At December 31, 2019, our “Accounts receivable, net” balance included $24.6 million for oil and gas sales, $3.7 million due from joint interest owners, $5.4 million for severance tax credit receivables and $3.3 million for other receivables.
Supervision Fees. Consistent with industry practice, we charge a supervision fee to the wells we operate, including our wells, in which we own up to a 100% working interest. Supervision fees are recorded as a reduction to “General and administrative, net,” on the accompanying condensed consolidated statements of operations. The amount of supervision fees charged for each of the nine months ended September 30, 2020 and 2019 did not exceed our actual costs incurred. The total amount of supervision fees charged to the wells we operated was $1.1 million for both the three months ended September 30, 2020 and 2019 and $3.2 million and $3.7 million for the nine months ended September 30, 2020 and 2019, respectively.
Income Taxes. Deferred taxes are determined based on the estimated future tax effects of differences between the financial statement and tax basis of assets and liabilities, given the provisions of the enacted tax laws. In March and April 2020, the COVID-19 pandemic caused volatility in the market price for crude oil due to the disruption of global supply and demand. In response to these market conditions and given the decline in oil prices and economic outlook for our Company, during the quarter ended June 30, 2020, management determined that it was not more likely than not that the Company would realize future cash benefits from its remaining federal carryover items and other deferred tax assets and, accordingly, recorded a full valuation allowance in the second quarter to offset its net deferred tax assets in excess of deferred tax liabilities. The Company’s effective tax rate was approximately 7.7% and (6.9)% for the three and nine months ended September 30, 2020, respectively. The difference in the Company’s effective tax rate and the statutory rate for the nine months ended September 30, 2020 related to the effects of recording a valuation allowance against the Company’s net deferred tax assets in the second quarter of 2020 and the state income tax provision. Our income tax benefit for the three months ended September 30, 2020 is fully attributable to a current state income tax benefit. The income tax benefit for the nine months ended September 30, 2019 was primarily the effect of releasing the valuation allowance previously recorded against the Company’s net deferred tax assets. During the second quarter of 2019, the Company was able to complete several operational initiatives that resulted in increased production, lower development costs and expanded inventory of development prospects. The results of these initiatives led management to determine, after weighing both positive and negative evidence, that the Company will more likely than not be able to realize the benefits of its deferred tax assets. Accordingly, the Company released the valuation allowance, resulting in an income tax benefit of $19.5 million for the nine months ended September 30, 2019.
Our policy is to record interest and penalties relating to uncertain tax positions in income tax expense. At September 30, 2020, we did not have any accrued liability for uncertain tax positions and do not anticipate recognition of any significant liabilities for uncertain tax positions during the next 12 months.
On March 27, 2020, President Trump signed into law the Coronavirus Aid, Relief, and Economic Security Act (the “CARES Act”). The CARES Act, among other things, includes provisions relating to refundable payroll tax credits, deferment of employer-side Social Security payments, net operating loss carryback periods, alternative minimum tax credit refunds and modifications to the net interest deduction limitation. The Company continues to examine the impact that the CARES Act may have on its business but does not currently expect the CARES Act to have a material effect on its financial condition, results of operation, or liquidity.
Revenue Recognition. Our reported oil and gas sales are comprised of revenues from oil, natural gas and natural gas liquids (“NGLs”) sales. Revenues from each product stream are recognized at the point when control of the product is transferred to the customer and collectability is reasonably assured. Prices for our products are either negotiated on a monthly basis or tied to market indices. The Company has determined that these contracts represent performance obligations which are satisfied when control of the commodity transfers to the customer, typically through the delivery of the specified commodity to a designated delivery point. Natural gas revenues are recognized based on the actual volume of natural gas sold to the purchasers.
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The following table provides information regarding our oil and gas sales, by product, reported on the Statements of Operations for the three months ended September 30, 2020 and 2019 and the nine months ended September 30, 2020 and 2019 (in thousands):
| Three Months Ended September 30, 2020 | Three Months Ended September 30, 2019 | Nine Months Ended September 30, 2020 | Nine Months Ended September 30, 2019 | ||||||||||||||||||||
| Oil, natural gas and NGLs sales: | |||||||||||||||||||||||
| Oil | $ | 17,665 | $ | 28,894 | $ | 40,979 | $ | 68,441 | |||||||||||||||
| Natural gas | 23,595 | 37,040 | 73,170 | 131,941 | |||||||||||||||||||
| NGLs | 4,439 | 6,080 | 9,772 | 18,400 | |||||||||||||||||||
| Total | $ | 45,699 | $ | 72,014 | $ | 123,921 | $ | 218,781 | |||||||||||||||
Accounts Payable and Accrued Liabilities. The “Accounts payable and accrued liabilities” balances on the accompanying condensed consolidated balance sheets are summarized below (in thousands):
| September 30, 2020 | December 31, 2019 | ||||||||||
| Trade accounts payable | $ | 8,063 | $ | 26,121 | |||||||
| Accrued operating expenses | 2,816 | 3,873 | |||||||||
| Accrued compensation costs | 3,414 | 4,601 | |||||||||
| Asset retirement obligations – current portion | 439 | 392 | |||||||||
| Accrued non-income based taxes | 4,133 | 1,413 | |||||||||
| Accrued corporate and legal fees | 162 | 109 | |||||||||
| Other payables | 3,680 | 2,834 | |||||||||
| Total accounts payable and accrued liabilities | $ | 22,707 | $ | 39,343 | |||||||
Cash and Cash Equivalents. We consider all highly liquid instruments with an initial maturity of three months or less to be cash equivalents. These amounts do not include cash balances that are contractually restricted.
Treasury Stock. Our treasury stock repurchases are reported at cost and are included in “Treasury stock, held at cost” on the accompanying condensed consolidated balance sheets. For the nine months ended September 30, 2020, we purchased 28,731 treasury shares to satisfy withholding tax obligations arising upon the vesting of restricted shares.
(3) Leases
The Company adopted the standard provided in the Financial Accounting Standards Board's Accounting Standards Update 2016-02 on January 1, 2019, using the modified retrospective transition approach. The Company has elected the package of practical expedients that allows an entity to carry forward historical accounting treatment relating to lease identification and classification for existing leases upon adoption and the practical expedient related to land easements that allows an entity to carry forward historical accounting treatment for land easements on existing agreements upon adoption. The Company has made an accounting policy election to keep leases with an initial term of 12 months or less off the Consolidated Balance Sheet. We have elected to not account for lease and non-lease components separately.
The Company has contractual agreements for its corporate office lease, vehicle fleet, compressors, treating equipment, and for surface use rights. For leases with a primary term of more than 12 months, a right-of-use (“ROU”) asset and the corresponding lease liability is recorded. The Company determines at inception if an arrangement is an operating or financing lease. As of September 30, 2020, all of the Company’s leases were operating leases.
The initial asset and liability balances are recorded at the present value of the payment obligations over the lease term. If lease terms include options to extend the lease and it is reasonably certain that the Company will exercise that option, the lease term used for capitalization includes the expected renewal periods. Most leases do not provide an implicit interest rate. Unless the lease contract contains an implicit interest rate, the Company uses its incremental borrowing rate at the time of lease inception to compute the fair value of the lease payments. The ROU asset balance and current and non-current lease liabilities are reported separately on the accompanying Condensed Consolidated Balance Sheet. Certain leases have payment terms that vary based on the usage of the underlying assets. Variable lease payments are not included in ROU assets and lease liabilities. Leases with an initial term of 12 months or less are not recorded on the balance sheet. The Company recognizes lease expense on a straight-line basis over the lease term.
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Lease costs represent the straight-line lease expense of ROU assets and short-term leases. The components of lease cost are classified as follows (in thousands):
| Three Months Ended September 30, 2020 | Three Months Ended September 30, 2019 | Nine Months Ended September 30, 2020 | Nine Months Ended September 30, 2019 | ||||||||||||||||||||
| Lease Costs Included in the Asset Additions in the Condensed Consolidated Balance Sheets | |||||||||||||||||||||||
| Property, plant and equipment acquisitions - short-term leases | $ | — | $ | 2,208 | $ | 2,302 | $ | 8,376 | |||||||||||||||
| Property, plant and equipment acquisitions - operating leases | — | 12 | 10 | 30 | |||||||||||||||||||
| Total lease costs in property, plant and equipment additions | $ | — | $ | 2,220 | $ | 2,312 | $ | 8,406 | |||||||||||||||
| Three Months Ended September 30, 2020 | Three Months Ended September 30, 2019 | Nine Months Ended September 30, 2020 | Nine Months Ended September 30, 2019 | ||||||||||||||||||||
| Lease Costs Included in the Condensed Consolidated Statements of Operations | |||||||||||||||||||||||
| Lease operating costs - short-term leases | $ | 124 | $ | 357 | $ | 575 | $ | 2,022 | |||||||||||||||
| Lease operating costs - operating leases | 1,397 | 1,387 | 4,267 | 2,524 | |||||||||||||||||||
| General and administrative, net - operating leases | 172 | 173 | 532 | 504 | |||||||||||||||||||
| Total lease cost expensed | $ | 1,693 | $ | 1,917 | $ | 5,374 | $ | 5,050 | |||||||||||||||
The lease term and the discount rate related to the Company's leases are as follows:
| September 30, 2020 | |||||
| Weighted-average remaining lease term (in years) | 1.7 | ||||
| Weighted-average discount rate | 4.6 | % | |||
As of September 30, 2020, the Company's future undiscounted cash payment obligation for its operating lease liabilities are as follows (in thousands):
| As of September 30, 2020 | |||||
| 2020 (Remaining) | $ | 1,772 | |||
| 2021 | 3,636 | ||||
| 2022 | 559 | ||||
| 2023 | 169 | ||||
| 2024 | 40 | ||||
| Thereafter | 310 | ||||
| Total undiscounted lease payments | 6,486 | ||||
| Present value adjustment | (287) | ||||
| Net operating lease liabilities | $ | 6,199 | |||
Supplemental cash flow information related to leases was as follows (in thousands):
| Nine Months Ended September 30, 2020 | Nine Months Ended September 30, 2019 | ||||||||||
| Cash paid for amounts included in the measurement of lease liabilities | |||||||||||
| Operating cash flows from operating leases | $ | 4,793 | $ | 3,013 | |||||||
| Investing cash flows from operating leases | $ | 10 | $ | 30 | |||||||
(4) Share-Based Compensation
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Share-Based Compensation Plans
In 2016, the Company adopted the 2016 Equity Incentive Plan (as amended from time to time, the “2016 Plan”). The Company also adopted the Inducement Plan (as amended from time to time, the “Inducement Plan,” and, together with the 2016 Plan, the “Plans”) on December 15, 2016. Under the Plans, the Company does not estimate the forfeiture rate during the initial calculation of compensation cost but rather has elected to account for forfeitures in compensation cost when they occur.
The Company computes a deferred tax benefit for restricted stock units (“RSUs”), performance-based stock units (“PSUs”) and stock options expected to generate future tax deductions by applying its effective tax rate to the expense recorded. For RSUs, the Company's actual tax deduction is based on the value of the units at the time of vesting.
The expense for awards issued to both employees and non-employees, which was recorded in “General and administrative, net” in the accompanying condensed consolidated statements of operations was $1.1 million and $1.8 million for the three months ended September 30, 2020 and 2019, respectively, and $3.5 million and $5.1 million for the nine months ended September 30, 2020 and 2019, respectively. Capitalized share-based compensation was less than $0.1 million and was $0.1 million for the three months ended September 30, 2020 and 2019, respectively, and $0.2 million and $0.4 million for the nine months ended September 30, 2020 and 2019, respectively.
We view stock option awards and RSUs with graded vesting as single awards with an expected life equal to the average expected life of component awards, and we amortize the awards on a straight-line basis over the life of the awards.
On April 2, 2019, our Board of Directors authorized a one-time grant of market-based awards (both RSUs and PSUs) in exchange for the cancellation of special equity awards (both RSUs and stock options) made to our named executive officers on August 9, 2018 (the “Equity Award Exchange”). As required under the terms of the 2016 Plan, this Equity Award Exchange was approved by the Company's shareholders on May 21, 2019. Pursuant to the Equity Award Exchange our executives were given the opportunity to exchange out-of-the-money or “underwater” stock options that were granted in August 2018 and certain RSUs also granted in August 2018 to receive a new equity award that consists of 50% time-based RSUs and 50% PSUs, granted under the 2016 Plan. The incremental compensation cost associated with the Equity Award Exchange was determined to be $1.2 million. This incremental cost was measured as the excess of the fair value of each new equity award, measured as of the date the new equity awards were granted, over the fair value of the stock options and RSUs surrendered in exchange for the new equity awards, measured immediately prior to the cancellation. This incremental compensation cost is being recognized ratably over the vesting period or performance period, as applicable, of the new equity awards.
Stock Option Awards
The compensation cost related to stock option awards is based on the grant date fair value and is typically expensed over the vesting period (generally one to five years). We use the Black-Scholes option pricing model to estimate the fair value of stock option awards.
At September 30, 2020, we had $0.7 million of unrecognized compensation cost related to stock option awards. The following table provides information regarding stock option award activity for the nine months ended September 30, 2020:
| Shares | Wtd. Avg. Exer. Price | ||||||||||
| Options outstanding, beginning of period | 324,324 | $ | 27.68 | ||||||||
| Options expired | (17,372) | $ | 26.96 | ||||||||
| Options outstanding, end of period | 306,952 | $ | 27.72 | ||||||||
| Options exercisable, end of period | 209,426 | $ | 28.39 | ||||||||
Our outstanding stock option awards at September 30, 2020 had no measurable aggregate intrinsic value. At September 30, 2020, the weighted-average remaining contract life of stock option awards outstanding was 5.0 years and exercisable was 4.3 years. The total intrinsic value of stock option awards exercisable had no value for the nine months ended September 30, 2020.
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Restricted Stock Units
The compensation cost related to these awards is based on the grant date fair value and is typically expensed over the requisite service period (generally one to five years).
As of September 30, 2020, we had $3.1 million unrecognized compensation expense related to our RSUs which is expected to be recognized over a weighted-average period of 1.3 years.
The following table provides information regarding RSU activity for the nine months ended September 30, 2020:
| RSUs | Wtd. Avg. Grant Price | ||||||||||
| RSUs outstanding, beginning of period | 342,683 | $ | 22.10 | ||||||||
| RSUs granted | 397,285 | $ | 2.83 | ||||||||
| RSUs forfeited | (1,794) | $ | 8.41 | ||||||||
| RSUs vested | (158,726) | $ | 21.38 | ||||||||
| RSUs outstanding, end of period | 579,448 | $ | 9.13 | ||||||||
Performance-Based Stock Units
On February 20, 2018, the Company granted 30,700 PSUs for which the number of shares earned is based on the total shareholder return (“TSR”) of the Company's common stock relative to the TSR of its selected peers during the performance period from January 1, 2018 to December 31, 2020. The awards contain market conditions which allow a payout ranging between 0% and 200% of the target payout. The fair value as of the grant date was $41.66 per unit or 150.6% of the stock price. The compensation expense for these awards is based on the per unit grant date valuation using a Monte Carlo simulation multiplied by the target payout level. The payout level is calculated based on actual stock price performance achieved during the performance period. The awards have a cliff-vesting period of three years.
On May 21, 2019, the Company granted an additional 99,500 PSUs (as part of the Equity Award Exchange discussed above) for which the number of shares earned is based on the TSR of the Company's common stock relative to the TSR of its selected peers during the performance period from January 1, 2019 to December 31, 2021. The awards contain market conditions which allow a payout ranging between 0% and 200% of the target payout. The fair value as of the grant date was $18.86 per unit or 112.9% of the stock price. The awards have a cliff-vesting period of three years.
As of September 30, 2020, we had $1.3 million unrecognized compensation expense related to our PSUs based on the assumption of 100% target payout. The remaining weighted-average performance period is 1.2 years. No shares vested during the nine months ended September 30, 2020.
(5) Earnings Per Share
Basic earnings per share (“Basic EPS”) has been computed using the weighted-average number of common shares outstanding during each period. Diluted earnings per share (“Diluted EPS”) assumes, as of the beginning of the period, exercise of stock options and RSU grants using the treasury stock method. Diluted EPS also assumes conversion of PSUs to common shares based on the number of shares (if any) that would be issuable, according to predetermined performance and market goals, if the end of the reporting period was the end of the performance period. Certain of our stock options and RSU grants that would potentially dilute Basic EPS in the future were also antidilutive for the three and nine months ended September 30, 2020 and 2019 are discussed below.
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The following is a reconciliation of the numerators and denominators used in the calculation of Basic EPS and Diluted EPS for the periods indicated below (in thousands, except per share amounts):
| Three Months Ended September 30, 2020 | Three Months Ended September 30, 2019 | ||||||||||||||||||||||||||||||||||
| Net Income (Loss) | Shares |
Per Share
Amount |
Net Income (Loss) | Shares |
Per Share
Amount |
||||||||||||||||||||||||||||||
| Basic EPS: | |||||||||||||||||||||||||||||||||||
| Net Income (Loss) and Share Amounts | $ | (6,896) | 11,935 | $ | (0.58) | $ | 27,651 | 11,762 | $ | 2.35 | |||||||||||||||||||||||||
| Dilutive Securities: | |||||||||||||||||||||||||||||||||||
| RSU Awards | — | 18 | |||||||||||||||||||||||||||||||||
| Diluted EPS: | |||||||||||||||||||||||||||||||||||
| Net Income (Loss) and Assumed Share Conversions | $ | (6,896) | 11,935 | $ | (0.58) | $ | 27,651 | 11,780 | $ | 2.35 | |||||||||||||||||||||||||
| Nine Months Ended September 30, 2020 | Nine Months Ended September 30, 2019 | ||||||||||||||||||||||||||||||||||
| Net Income (Loss) | Shares | Per Share Amount | Net Income (Loss) | Shares | Per Share Amount | ||||||||||||||||||||||||||||||
| Basic EPS: | |||||||||||||||||||||||||||||||||||
| Net Income (Loss) and Share Amounts | $ | (318,730) | 11,890 | $ | (26.81) | $ | 108,408 | 11,739 | $ | 9.24 | |||||||||||||||||||||||||
| Dilutive Securities: | |||||||||||||||||||||||||||||||||||
| RSU Awards | — | 37 | |||||||||||||||||||||||||||||||||
| Diluted EPS: | |||||||||||||||||||||||||||||||||||
| Net Income (Loss) and Assumed Share Conversions | $ | (318,730) | 11,890 | $ | (26.81) | $ | 108,408 | 11,776 | $ | 9.21 | |||||||||||||||||||||||||
Approximately 0.3 million stock options to purchase shares were not included in the computation of Diluted EPS for the three months ended September 30, 2020 because they were antidilutive due to the net loss, and 0.4 million stock options to purchase shares were not included in the computation of Diluted EPS for the three months ended September 30, 2019 because they were antidilutive, while 0.3 million stock options to purchase shares were not included for the nine months ended September 30, 2020 because they were antidilutive due to the net loss, and 0.5 million stock options to purchase shares were not included in the computation of Diluted EPS for the nine months ended September 30, 2019 because they were antidilutive.
Approximately 0.2 million of RSUs that could be converted to common shares were not included in the computation of Diluted EPS for the three months ended September 30, 2020 because they were antidilutive due to the net loss, and 0.4 million of RSUs that could be converted to common shares were not included in the computation of Diluted EPS for the three months ended September 30, 2019, because they were antidilutive, while 0.2 million of RSUs that could be converted to common shares were not included in the computation of Diluted EPS for the nine months ended September 30, 2020 because they were antidilutive due to the net loss, and approximately 0.1 million of RSUs that could be converted to common shares were not included in the computation of Diluted EPS for the nine months ended September 30, 2019 because they were antidilutive.
Approximately 0.1 million shares of PSUs that could be converted to common shares were not included in the computation of Diluted EPS for the three months ended September 30, 2020 because they were antidilutive due to the net loss, and approximately 0.1 million shares of PSUs were not included for the three months ended September 30, 2019 because they were antidilutive, while 0.1 million shares of PSUs were not included for the nine months ended September 30, 2020 because they were antidilutive due to the net loss, and approximately 0.1 million shares of PSUs were not included for the nine months ended September 30, 2019 because they were antidilutive.
Approximately 2.1 million warrants to purchase common stock were not included in the computation of Diluted EPS for the three and nine months ended September 30, 2019 because these warrants were antidilutive. There were no warrants to purchase common stock for the three and nine months ended September 30, 2020 as the warrants expired.
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(6) Long-Term Debt
The Company's long-term debt consisted of the following (in thousands):
| September 30, 2020 | December 31, 2019 | ||||||||||
|
Credit Facility Borrowings (1)
|
$ | 253,000 | $ | 279,000 | |||||||
| Second Lien Notes due 2024 | 200,000 | 200,000 | |||||||||
| 453,000 | 479,000 | ||||||||||
| Unamortized discount on Second Lien Notes due 2024 | (1,361) | (1,550) | |||||||||
| Unamortized debt issuance cost on Second Lien Notes due 2024 | (3,995) | (4,550) | |||||||||
| Long-Term Debt, net | $ | 447,644 | $ | 472,900 | |||||||
(1) Unamortized debt issuance costs on our Credit Facility borrowings are included in “Other Long-Term Assets” in our consolidated balance sheet. As of September 30, 2020 and December 31, 2019, we had $1.7 million and $3.1 million, respectively, in unamortized debt issuance costs on our Credit Facility borrowings.
Revolving Credit Facility. Amounts outstanding under our Credit Facility (defined below) were $253.0 million and $279.0 million as of September 30, 2020 and December 31, 2019, respectively. The Company is a party to a First Amended and Restated Senior Secured Revolving Credit Agreement with JPMorgan Chase Bank, National Association, as administrative agent, and certain lenders party thereto, as amended (such agreement, the “Credit Agreement” and the borrowing facility provided thereby, the “Credit Facility”). The Company entered into the Sixth Amendment to the Credit Facility, effective November 2, 2020 (the “Sixth Amendment”), which among other things, (i) decreased the borrowing base under the Credit Facility to $310 million (from $330 million) as part of the regularly scheduled semi-annual redetermination and (ii) decreased the ratio of total debt to EBITDA (defined below) to not exceed 3.5 to 1.0.
The Credit Facility matures April 19, 2022, and provides for a maximum credit amount of $600 million, subject to the current borrowing base of $310 million as of November 2, 2020. The borrowing base is regularly redetermined on or about May and November of each calendar year and is subject to additional adjustments from time to time, including for asset sales, elimination or reduction of hedge positions and incurrence of other debt. Additionally, the Company and the administrative agent may request an unscheduled redetermination of the borrowing base between scheduled redeterminations. The amount of the borrowing base is determined by the lenders, in their discretion, in accordance with their oil and gas lending criteria at the time of the relevant redetermination. The Company may also request the issuance of letters of credit under the Credit Agreement in an aggregate amount up to $25 million, which reduces the amount of available borrowings under the borrowing base in the amount of such issued and outstanding letters of credit.
Interest under the Credit Facility accrues at the Company’s option either at an Alternate Base Rate plus the applicable margin (“ABR Loans”) or the LIBOR Rate plus the applicable margin (“Eurodollar Loans”). Since May 12, 2020, the applicable margin ranged from 1.75% to 2.75% for ABR Loans and 2.75% to 3.75% for Eurodollar Loans. The Alternate Base Rate and LIBOR Rate are defined, and the applicable margins are set forth, in the Credit Agreement. Undrawn amounts under the Credit Facility are subject to a 0.5% commitment fee. To the extent that a payment default exists and is continuing, all amounts outstanding under the Credit Facility will bear interest at 2.0% per annum above the rate and margin otherwise applicable thereto. In July 2017, the United Kingdom’s Financial Conduct Authority, which regulates LIBOR, announced that it intends to phase out LIBOR by the end of 2021. At the present time, the Credit Facility is subject to LIBOR rates but has a term that extends beyond the end of 2021 when LIBOR will be phased out. The Sixth Amendment includes technical updates to address this matter, and we are currently evaluating the potential impact of eventual replacement of the LIBOR interest rate.
The obligations under the Credit Agreement are secured, subject to certain exceptions, by a first priority lien on substantially all assets of the Company and its subsidiary, including a first priority lien on properties attributed with at least 85% of estimated proved reserves of the Company and its subsidiary.
The Credit Agreement contains the following financial covenants:
•a ratio of total debt to earnings before interest, tax, depreciation and amortization (“EBITDA”), as defined in the Credit Agreement, for the most recently completed four fiscal quarters, not to exceed (i) 4.0 to 1.0 as of the last day of each fiscal quarter for any fiscal quarter ending on or before September 30, 2020 and (ii) 3.5 to 1.0 as of the last day of each fiscal quarter, commencing with fiscal quarter ending December 31, 2020; and
•a current ratio, as defined in the Credit Agreement, which includes in the numerator available borrowings undrawn under the borrowing base, of not less than 1.0 to 1.0 as of the last day of each fiscal quarter.
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As of September 30, 2020, the Company was in compliance with all financial covenants under the Credit Agreement. Maintaining or increasing our borrowing base under our Credit Facility is dependent on many factors, including commodity prices, our hedge positions, changes in our lenders' lending criteria and our ability to raise capital to drill wells to replace produced reserves.
Additionally, the Credit Agreement contains certain representations, warranties and covenants, including but not limited to, limitations on incurring debt and liens, limitations on making certain restricted payments, limitations on investments, limitations on asset sales and hedge unwinds, limitations on transactions with affiliates and limitations on modifying organizational documents and material contracts. The Credit Agreement contains customary events of default. If an event of default occurs and is continuing, the lenders may declare all amounts outstanding under the Credit Facility to be immediately due and payable.
Total interest expense on the Credit Facility, which includes commitment fees and amortization of debt issuance costs, was $2.9 million and $4.2 million for the three months ended September 30, 2020 and 2019, respectively, and $9.8 million and $11.7 million for the nine months ended September 30, 2020 and 2019, respectively.
There was no capitalized interest on our unproved properties for both the three months ended September 30, 2020 and 2019, respectively, and no capitalized interest and $0.2 million in capitalized interest on our unproved properties for the nine months ended September 30, 2020 and 2019, respectively.
Senior Secured Second Lien Notes. On December 15, 2017, the Company entered into a Note Purchase Agreement for Senior Secured Second Lien Notes (as amended, the “Note Purchase Agreement,” and such second lien facility the “Second Lien”) among the Company as issuer, U.S. Bank National Association as agent and collateral agent, and certain holders that are a party thereto, and issued notes in an initial principal amount of $200.0 million, with a $2.0 million discount, for net proceeds of $198.0 million. The Company has the ability, subject to the satisfaction of certain conditions (including compliance with the Asset Coverage Ratio described below and the agreement of the holders to purchase such additional notes), to issue additional notes in a principal amount not to exceed $100.0 million. The Second Lien matures on December 15, 2024.
Interest on the Second Lien is payable quarterly and accrues at LIBOR plus 7.5%; provided that if LIBOR ceases to be available, the Second Lien provides for a mechanism to use ABR (an alternate base rate) plus 6.5% as the applicable interest rate. The definitions of LIBOR and ABR are set forth in the Note Purchase Agreement. To the extent that a payment, insolvency, or, at the holders’ election, another default exists and is continuing, all amounts outstanding under the Second Lien will bear interest at 2.0% per annum above the rate and margin otherwise applicable thereto. Additionally, to the extent the Company were to default on the Second Lien, this would potentially trigger a cross-default under our Credit Facility.
The Company has the right, to the extent permitted under the Credit Facility and subject to the terms and conditions of the Second Lien, to optionally prepay the notes, subject to the following repayment fees; during year three, 2.0% of the principal amount of the Second Lien being prepaid; during year four, 1.0% of the principal amount of the Second Lien being prepaid; and thereafter, no premium. Additionally, the Second Lien contains customary mandatory prepayment obligations upon asset sales (including hedge terminations), casualty events and incurrences of certain debt, subject to, in certain circumstances, reinvestment periods. Management believes the probability of mandatory prepayment due to default is remote.
The obligations under the Second Lien are secured, subject to certain exceptions and other permitted liens (including the liens created under the Credit Facility), by a perfected security interest, second in priority to the liens securing our Credit Facility, and mortgage lien on substantially all assets of the Company and its subsidiary, including a mortgage lien on oil and gas properties attributed with at least 85% of estimated PV-9 (defined below), of proved reserves of the Company and its subsidiary and 85% of the book value attributed to the PV-9 of the non-proved oil and gas properties of the Company. PV-9 is determined using commodity price assumptions by the administrative agent of the Credit Facility. PV-9 value is the estimated future net revenues to be generated from the production of proved reserves discounted to present value using an annual discount rate of 9%.
The Second Lien contains an Asset Coverage Ratio, which is only tested (i) as a condition to issuance of additional notes and (ii) in connection with certain asset sales in order to determine whether the proceeds of such asset sale must be applied as a prepayment of the notes and includes in the numerator of the PV-10 (defined below), based on forward strip pricing, plus the swap mark-to-market value of the commodity derivative contracts of the Company and its restricted subsidiary and in the denominator the total net indebtedness of the Company and its restricted subsidiary, of not less than 1.25 to 1.0 as of each date of determination (the “Asset Coverage Ratio”). PV-10 value is the estimated future net revenues to be generated from the production of proved reserves discounted to present value using an annual discount rate of 10%.
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The Second Lien also contains a financial covenant measuring the ratio of total net debt-to-EBITDA, as defined in the Note Purchase Agreement, for the most recently completed four fiscal quarters, not to exceed 4.5 to 1.0 as of the last day of each fiscal quarter. As of September 30, 2020, the Company was in compliance with all financial covenants under the Second Lien.
The Second Lien contains certain customary representations, warranties and covenants, including but not limited to, limitations on incurring debt and liens, limitations on making certain restricted payments, limitations on investments, limitations on asset sales and hedge unwinds, limitations on transactions with affiliates and limitations on modifying organizational documents and material contracts. The Second Lien contains customary events of default. If an event of default occurs and is continuing, the lenders may declare all amounts outstanding under the Second Lien to be immediately due and payable.
As of September 30, 2020, total net amounts recorded for the Second Lien were $194.6 million, net of unamortized debt discount and debt issuance costs. Interest expense on the Second Lien totaled $4.6 million and $5.2 million for the three months ended September 30, 2020 and 2019, respectively, and $14.1 million and $16.0 million for the nine months ended September 30, 2020 and 2019, respectively.
Debt Issuance Costs. Our policy is to capitalize upfront commitment fees and other direct expenses associated with our line of credit arrangement and then amortize such costs ratably over the term of the arrangement, regardless of whether there are any outstanding borrowings.
(7) Acquisitions and Dispositions
Effective December 22, 2017, the Company closed a purchase and sale contract to sell the Company's wellbores and facilities in the Bay De Chene field and recorded a $16.3 million obligation related to the funding of certain plugging and abandonment costs. Of the $16.3 million original obligation, $0.4 million and $4.4 million was paid during the nine months ended September 30, 2020 and 2019, respectively. The remaining obligation under this contract is $2.0 million and is carried in the accompanying condensed consolidated balance sheet current liability in “Accounts payable and accrued liabilities” as of September 30, 2020.
On April 3, 2020, we acquired additional properties in the Eagle Ford for approximately $5.0 million, including assumed liabilities. The acquisition included eight producing wells, basic infrastructure and acreage in Webb, La Salle, and McMullen Counties. We allocated all of the purchase price to proved oil and gas properties.
On May 13, 2020, the Company divested an overriding royalty interest in Converse and Niobrara Counties, Wyoming for approximately $4.8 million. The sales of our Wyoming assets did not significantly alter the relationship between capitalized costs and proved reserves, and as such, all proceeds were recorded as adjustments to our domestic full cost pool with no gain or loss recognized. These consolidated financial statements include the results of our Wyoming operations through the date of sale.
(8) Price-Risk Management Activities
Derivatives are recorded on the balance sheet at fair value with changes in fair value recognized in earnings. The changes in the fair value of our derivatives are recognized in “Gain (loss) on commodity derivatives, net” on the accompanying condensed consolidated statements of operations. We have a price-risk management policy to use derivative instruments to protect against declines in oil and natural gas prices, primarily through the purchase of commodity price swaps and collars as well as basis swaps.
During the three months ended September 30, 2020 and 2019, the Company recorded losses of $12.9 million and gains of $13.4 million, respectively, on its commodity derivatives. During the nine months ended September 30, 2020 and 2019, the Company recorded gains of $66.9 million and $34.3 million, respectively. The Company collected cash payments of $76.1 million and $16.1 million for settled derivative contracts during the nine months ended September 30, 2020 and 2019, respectively. Included in our collected cash payments during the nine months ended September 30, 2020 was $38.3 million for monetized derivative contracts received in the first quarter of 2020.
At September 30, 2020, there were $2.7 million in receivables for settled derivatives while at December 31, 2019, we had $2.9 million in receivables for settled derivatives which were included on the accompanying condensed consolidated
21
balance sheet in “Accounts receivable, net” and were subsequently collected in October 2020 and January 2020, respectively. At September 30, 2020 and December 31, 2019, we also had $0.5 million and $0.2 million, respectively, in payables for settled derivatives which were included on the accompanying condensed consolidated balance sheet in “Accounts payable and accrued liabilities” and were subsequently paid in October 2020 and January 2020, respectively.
The fair values of our swap contracts are computed using observable market data whereas our collar contracts are valued using a Black-Scholes pricing model and are periodically verified against quotes from brokers. At September 30, 2020, there was $11.8 million and $2.3 million in current unsettled derivative assets and long-term unsettled derivative assets, respectively, and $10.4 million and $4.0 million in current and long-term unsettled derivative liabilities, respectively. At December 31, 2019, there was $12.8 million and $3.9 million in current and long-term unsettled derivative assets, respectively, and $6.6 million and $1.6 million in current and long-term unsettled derivative liabilities, respectively.
The Company uses an International Swap and Derivatives Association master agreement for our derivative contracts. This is an industry-standardized contract containing the general conditions of our derivative transactions including provisions relating to netting derivative settlement payments under certain circumstances (such as default). For reporting purposes, the Company has elected to not offset the asset and liability fair value amounts of its derivatives on the accompanying balance sheets. Under the right of set-off, there was a $0.3 million net fair value liability at September 30, 2020, and an $8.4 million net fair value asset at December 31, 2019. For further discussion related to the fair value of the Company's derivatives, refer to Note 9 of these Notes to Condensed Consolidated Financial Statements.
The following tables summarize the weighted-average prices as well as future production volumes for our future derivative contracts in place as of September 30, 2020:
|
Oil Derivative Swaps
(New York Mercantile Exchange (“NYMEX”) WTI Settlements) |
Total Volumes
(Bbls) |
Weighted-Average Price | Weighted-Average Collar Floor Price | Weighted-Average Collar Call Price | |||||||||||||||||||
| 2020 Contracts | |||||||||||||||||||||||
| 4Q20 | 353,626 | $ | 47.72 | ||||||||||||||||||||
| 2021 Contracts | |||||||||||||||||||||||
| 1Q21 | 215,538 | $ | 51.93 | ||||||||||||||||||||
| 2Q21 | 195,646 | $ | 51.93 | ||||||||||||||||||||
| 3Q21 | 179,759 | $ | 51.19 | ||||||||||||||||||||
| 4Q21 | 163,812 | $ | 52.39 | ||||||||||||||||||||
| 2022 Contracts | |||||||||||||||||||||||
| 1Q22 | 88,455 | $ | 36.79 | ||||||||||||||||||||
| Collar Contracts | |||||||||||||||||||||||
| 2020 Contracts | |||||||||||||||||||||||
| 4Q20 | 115,000 | $ | 31.00 | $ | 36.15 | ||||||||||||||||||
| 2021 Contracts | |||||||||||||||||||||||
| 1Q21 | 155,475 | $ | 34.15 | $ | 39.24 | ||||||||||||||||||
| 2Q21 | 116,980 | $ | 34.33 | $ | 40.30 | ||||||||||||||||||
| 3Q21 | 90,620 | $ | 34.34 | $ | 39.87 | ||||||||||||||||||
| 4Q21 | 84,640 | $ | 34.70 | $ | 41.01 | ||||||||||||||||||
| 2022 Contracts | |||||||||||||||||||||||
| 2Q22 | 86,450 | $ | 39.00 | $ | 46.50 | ||||||||||||||||||
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|
Natural Gas Derivative Contracts
(NYMEX Henry Hub Settlements) |
Total Volumes
(MMBtu) |
Weighted-Average Price | Weighted-Average Collar Floor Price | Weighted-Average Collar Call Price | |||||||||||||||||||
| 2020 Contracts | |||||||||||||||||||||||
| 4Q20 | 7,817,000 | $ | 2.63 | ||||||||||||||||||||
| 2021 Contracts | |||||||||||||||||||||||
| 1Q21 | 2,398,078 | $ | 2.74 | ||||||||||||||||||||
| 2Q21 | 832,255 | $ | 2.42 | ||||||||||||||||||||
| 3Q21 | 330,000 | $ | 2.62 | ||||||||||||||||||||
| 4Q21 | 290,000 | $ | 2.69 | ||||||||||||||||||||
| Collar Contracts | |||||||||||||||||||||||
| 2020 Contracts | |||||||||||||||||||||||
| 4Q20 | 920,000 | $ | 2.57 | $ | 2.93 | ||||||||||||||||||
| 2021 Contracts | |||||||||||||||||||||||
| 1Q21 | 7,027,800 | $ | 2.53 | $ | 3.33 | ||||||||||||||||||
| 2Q21 | 4,546,000 | $ | 2.18 | $ | 2.69 | ||||||||||||||||||
| 3Q21 | 4,665,175 | $ | 2.02 | $ | 2.65 | ||||||||||||||||||
| 4Q21 | 4,391,000 | $ | 2.25 | $ | 2.71 | ||||||||||||||||||
| 2022 Contracts | |||||||||||||||||||||||
| 1Q22 | 4,415,000 | $ | 2.50 | $ | 3.35 | ||||||||||||||||||
| 2Q22 | 4,200,000 | $ | 2.23 | $ | 2.70 | ||||||||||||||||||
|
Natural Gas Basis Derivative Swap
(East Texas Houston Ship Channel vs. NYMEX Settlements) |
Total Volumes
(MMBtu) |
Weighted-Average Price | |||||||||
| 2020 Contracts | |||||||||||
| 4Q20 | 11,868,000 | $ | (0.04) | ||||||||
| 2021 Contracts | |||||||||||
| 1Q21 | 9,900,000 | $ | (0.02) | ||||||||
| 2Q21 | 10,010,000 | $ | (0.02) | ||||||||
| 3Q21 | 10,120,000 | $ | (0.02) | ||||||||
| 4Q21 | 10,120,000 | $ | (0.02) | ||||||||
|
Oil Basis Contracts
(Argus Cushing (WTI) and Magellan East Houston) |
Total Volumes (Bbls) | Weighted-Average Price | |||||||||
| 2020 Contracts | |||||||||||
| 4Q20 | 465,275 | $ | 1.20 | ||||||||
| 2021 Contracts | |||||||||||
| 1Q21 | 373,750 | $ | 1.19 | ||||||||
| 2Q21 | 329,150 | $ | 1.22 | ||||||||
| 3Q21 | 262,200 | $ | 1.27 | ||||||||
| 4Q21 | 241,500 | $ | 1.28 | ||||||||
| Calendar Monthly Roll Differential Swaps | |||||||||||
| 2020 Contracts | |||||||||||
| 4Q20 | 469,900 | $ | (0.02) | ||||||||
| 2021 Contracts | |||||||||||
| 1Q21 | 367,000 | $ | (0.40) | ||||||||
| 2Q21 | 313,900 | $ | (0.37) | ||||||||
| 3Q21 | 253,000 | $ | (0.34) | ||||||||
| 4Q21 | 241,500 | $ | (0.33) | ||||||||
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(9) Fair Value Measurements
Fair Value on a Recurring Basis. Our financial instruments consist of cash and cash equivalents, accounts receivable, accounts payable, derivatives, the Credit Facility and the Second Lien. The carrying amounts of cash and cash equivalents, accounts receivable, and accounts payable approximate fair value due to the highly liquid or short-term nature of these instruments.
The fair values of our derivative contracts are computed using observable market data whereas our derivative collar contracts are valued using a Black-Scholes pricing model and are periodically verified against quotes from brokers. These are considered Level 2 valuations (defined below).
The carrying value of our Credit Facility and Second Lien approximates fair value because the respective borrowing rates do not materially differ from market rates for similar borrowings. These are considered Level 3 valuations (defined below).
The fair value hierarchy has three levels based on the reliability of the inputs used to determine the fair value (in millions):
Level 1 – Uses quoted prices in active markets for identical, unrestricted assets or liabilities. Instruments in this category have comparable fair values for identical instruments in active markets.
Level 2 – Uses quoted prices for similar assets or liabilities in active markets or observable inputs for assets or liabilities in non-active markets. Instruments in this category are periodically verified against quotes from brokers and include our commodity derivatives that we value using commonly accepted industry-standard models which contain inputs such as contract prices, risk-free rates, volatility measurements and other observable market data that are obtained from independent third-party sources.
Level 3 – Uses unobservable inputs for assets or liabilities that are in non-active markets.
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The following table presents our assets and liabilities that are measured on a recurring basis at fair value as of each of September 30, 2020 and December 31, 2019, and are categorized using the fair value hierarchy. For additional discussion related to the fair value of the Company's derivatives, refer to Note 8 of these Notes to Condensed Consolidated Financial Statements.
| Fair Value Measurements at | |||||||||||||||||||||||
| (in millions) | Total |
Quoted Prices in
Active markets for Identical Assets (Level 1) |
Significant Other
Observable Inputs (Level 2) |
Significant
Unobservable Inputs (Level 3) |
|||||||||||||||||||
| September 30, 2020 | |||||||||||||||||||||||
| Assets | |||||||||||||||||||||||
| Natural Gas Derivatives | $ | 0.3 | $ | — | $ | 0.3 | $ | — | |||||||||||||||
| Natural Gas Basis Derivatives | $ | 3.0 | $ | — | $ | 3.0 | $ | — | |||||||||||||||
| Oil Derivatives | $ | 10.0 | $ | — | $ | 10.0 | $ | — | |||||||||||||||
| Oil Basis Derivatives | $ | 0.8 | $ | — | $ | 0.8 | $ | — | |||||||||||||||
| Liabilities | |||||||||||||||||||||||
| Natural Gas Derivatives | $ | 10.7 | $ | — | $ | 10.7 | $ | — | |||||||||||||||
| Natural Gas Basis Derivatives | $ | 0.1 | $ | — | $ | 0.1 | $ | — | |||||||||||||||
| Oil Derivatives | $ | 3.4 | $ | — | $ | 3.4 | $ | — | |||||||||||||||
| Oil Basis Derivatives | $ | 0.2 | $ | — | $ | 0.2 | $ | — | |||||||||||||||
| December 31, 2019 | |||||||||||||||||||||||
| Assets | |||||||||||||||||||||||
| Natural Gas Derivatives | $ | 11.7 | $ | — | $ | 11.7 | $ | — | |||||||||||||||
| Natural Gas Basis Derivatives | $ | 3.4 | $ | — | $ | 3.4 | $ | — | |||||||||||||||
| Oil Derivatives | $ | 1.6 | $ | — | $ | 1.6 | $ | — | |||||||||||||||
| Liabilities | |||||||||||||||||||||||
| Natural Gas Derivatives | $ | 0.2 | $ | — | $ | 0.2 | $ | — | |||||||||||||||
| Natural Gas Basis Derivatives | $ | 0.9 | $ | — | $ | 0.9 | $ | — | |||||||||||||||
| Oil Derivatives | $ | 7.0 | $ | — | $ | 7.0 | $ | — | |||||||||||||||
| Oil Basis Derivatives | $ | 0.1 | $ | — | $ | 0.1 | $ | — | |||||||||||||||
Our current and long-term unsettled derivative assets and liabilities in the table above are measured at gross fair value and are shown on the accompanying condensed consolidated balance sheets in “Fair value of commodity derivatives” and “Fair Value of Long-Term Commodity Derivatives,” respectively.
(10) Asset Retirement Obligations
Liabilities for legal obligations associated with the retirement obligations of tangible long-lived assets are initially recorded at fair value in the period in which they are incurred. When a liability is initially recorded, the carrying amount of the related asset is increased. The liability is discounted from the expected date of abandonment. Over time, accretion of the liability is recognized each period, and the capitalized cost is amortized on a unit-of-production basis as part of depreciation, depletion, and amortization expense for our oil and gas properties. Upon settlement of the liability, the Company either settles the obligation for its recorded amount or incurs a gain or loss upon settlement which is included in the “Property and Equipment” balance on our accompanying condensed consolidated balance sheets. This guidance requires us to record a liability for the fair value of our dismantlement and abandonment costs, excluding salvage values.
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The following provides a roll-forward of our asset retirement obligations for the year ended December 31, 2019 and the nine months ended September 30, 2020 (in thousands):
| Asset Retirement Obligations as of December 31, 2018 | $ | 4,259 | |||
| Accretion expense | 329 | ||||
| Liabilities incurred for new wells and facilities construction | 250 | ||||
| Reductions due to plugged wells and facilities | (82) | ||||
| Revisions in estimates | (309) | ||||
| Asset Retirement Obligations as of December 31, 2019 | $ | 4,447 | |||
| Accretion expense | 263 | ||||
| Liabilities incurred for new wells and facilities construction | 165 | ||||
| Reductions due to plugged wells and facilities | (92) | ||||
| Asset Retirement Obligations as of September 30, 2020 | $ | 4,783 | |||
At both September 30, 2020 and December 31, 2019, approximately $0.4 million of our asset retirement obligations were classified as a current liability in “Accounts payable and accrued liabilities” on the accompanying consolidated balance sheets.
(11) Commitments and Contingencies
In the ordinary course of business, we are party to various legal actions, which arise primarily from our activities as an operator of oil and natural gas wells. In our management's opinion, the outcome of any such currently pending legal actions will not have a material adverse effect on our financial position or results of operations.
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Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations
You should read the following discussion and analysis in conjunction with the Company's financial information and its consolidated financial statements and accompanying notes included in this report and its Annual Report on Form 10-K for the year ended December 31, 2019. The following information contains forward-looking statements; see “Forward-Looking Statements” on page 38 of this report.
Company Overview
SilverBow is an independent oil and gas company headquartered in Houston, Texas. The Company's strategy is focused on acquiring and developing assets in the Eagle Ford Shale located in South Texas where it has assembled approximately 167,000 net acres across five operating areas. SilverBow's acreage position in each of its operating areas is highly contiguous and designed for optimal and efficient horizontal well development. The Company has built a balanced portfolio of properties with a significant base of current production and reserves coupled with low-risk development drilling opportunities and meaningful upside from newer operating areas.
Being a committed and long-term operator in South Texas, SilverBow possesses a significant understanding of the reservoir characteristics, geology, landowners and competitive landscape in the region. The Company leverages this in-depth knowledge to continue to assemble high quality drilling inventory while continuously enhancing its operations to maximize returns on capital invested.
Recent Events, Actions Taken and Strategy
In March, the spot price of WTI crude oil declined over 50% in response to reductions in global demand due to the COVID-19 pandemic and announcements by Saudi Arabia and Russia of plans to increase crude oil production. Following this unprecedented collapse in crude oil prices, the spot price of Brent and WTI crude oil closed at approximately $15 and $21 per barrel, respectively, on March 31, 2020. Crude oil prices fell further in April but partially recovered during the second quarter of 2020 with Brent and WTI crude oil closing at approximately $41 and $39 per barrel, respectively on June 30, 2020. Crude oil prices traded slightly higher in the third quarter of 2020 with Brent and WTI crude closing at approximately $42 and $40 per barrel, on September 30, 2020.
The ultimate magnitude and duration of the COVID-19 pandemic, resulting governmental restrictions placing limitations on the mobility and ability to work of significant portions of the worldwide population, and the related impact on crude oil prices and the U.S. and global economy and capital markets is uncertain. While it is difficult to assess or predict with precision the broad future effect of this pandemic on the global economy, the energy industry or SilverBow, management expects that the pandemic will negatively affect the Company's results of operations, cash flows and financial condition during the remainder of 2020 due to lower commodity prices and varied production levels.
In response to market conditions, including the COVID-19 pandemic and the rapid decline in commodity prices and economic outlook, SilverBow reduced its original 2020 capital budget of $175-$195 million. The Company released its sole drilling rig in April 2020, and deferred the completion and placement on production of eight wells until the second half of 2020. In the third quarter of 2020, SilverBow restarted completions activity and returned to sales all previously curtailed oil volumes and a substantial portion of natural gas volumes. Approximately 20 MMcf/d of net gas production remained shut-in at quarter-end. The Company began returning these volumes to production in late October to align with favorable fundamentals and a strong natural gas price environment.
With the addition of a drilling rig in the fourth quarter of 2020, SilverBow reaffirmed its capital budget for the full year 2020 of $95-$105 million. As with the Company's completion activities, SilverBow will continue to assess optimal production timing in response to the dynamic commodity price environment. The re-imposition of restrictions by governments to mitigate the COVID-19 pandemic or other events that adversely affect crude oil prices could result in further curtailments and adversely affect our expectation for improved performance during the remainder of 2020 and 2021.
Overall, the Company's strategy of procuring cost savings on drilling and completion activities allows SilverBow to add activity and stay within its capital range. The Company plans to continue pursuing a single-basin operating model, focused on its low-cost structure and optionality across multiple commodity phase windows of the Eagle Ford. As a returns-focused operator, SilverBow employs a risk mitigation strategy by hedging forecasted production volumes and protecting cash flow.
As a result of the COVID-19 pandemic, the Company continues to operate under a "work from home" policy applicable to all employees other than essential personnel whose physical presence is required either in the office or in the field.
27
SilverBow has not experienced any material interruption to its ordinary course business processes as a result of COVID-19. The Company will continue to monitor the COVID-19 situation and follow the advice of government and health leaders.
Operational Results
Total production for the nine months ended September 30, 2020 decreased 20% from the nine months ended September 30, 2019 to 184 million cubic feet of natural gas equivalent per day due to curtailed production volumes.
During the third quarter of 2020, SilverBow resumed completion activity by bringing online eight wells in its McMullen Oil area. The Company completed three of these wells in the first quarter of 2020, but deferred bringing them online due to prevailing market conditions. The remaining five wells were drilled but uncompleted during the first quarter of 2020. As planned, all eight of these oil-weighted wells were placed on production in the third quarter of 2020, with the five DUCs completed nearly one month ahead of schedule. SilverBow's total well costs for the five DUCs were $8 million below budget, collectively. In addition to resuming capital activity, all remaining curtailed oil volumes were returned to sales during the third quarter. Approximately 20 MMcf/d of net gas production remained shut-in at quarter-end. The Company returned these volumes to production in late October to align with favorable natural gas prices.
To date, wells that have been returned to sales have not experienced any degradation and in some cases have exhibited higher production rates compared to pre-shut-in levels, as noted last quarter. SilverBow continues to monitor and analyze well data in real-time and implement choke management practices that optimize and preserve the integrity of each well. The Company believes these are primary drivers for the strong performance of the wells returned to sales.
The operations team carried out significant pre-planning and contingency practices, and engaged in rigorous vendor bidding activities, to ensure continuation of the Company’s low-cost platform and operational efficiencies given the activity hiatus in the second quarter of 2020. The team also performed regular, in-depth reviews of operating and capital costs. On the operating cost side, labor, compression, salt-water disposal and chemicals were the notable areas that led to further LOE savings. On the capital side, service-pricing remains in a deflationary environment and the SilverBow team has been able to capture further savings through selective de-bundling of capital costs and process efficiencies.
At the beginning of October, the Company resumed drilling activity in the Webb County Gas area. SilverBow drilled the first three wells in the Upper Eagle Ford at Fasken with first production expected towards year-end. The other six wells comprise the second, co-developed La Mesa pad. The first pad was drilled and completed last year and has demonstrated some of the strongest returns in the Company's portfolio. SilverBow expects to finish the drilling and completion of the six-well La Mesa pad in early 2021, with first sales expected by the end of the first quarter.
For the full year 2020, the Company expects capital expenditures to be at the high end of the $95-$100 million range.
2020 Cost Reduction Initiatives: SilverBow continues to focus on cost reduction measures in the areas that it can control. These initiatives include the use of regional sand in completions, improved utilization of existing facilities, elimination of redundant equipment, and replacement of rental equipment with company-owned equipment. As previously mentioned, the Company continues to improve its process for drilling, completing and equipping wells. SilverBow's procurement team takes a process-oriented approach to reducing the total delivered costs of purchased services by examining costs at their most granular level. Services are routinely sourced directly from the suppliers. The Company's LOE and workover expenses were $16.0 million or $0.32 per thousand cubic feet of gas equivalent ("Mcfe") for the first nine months of 2020, as compared to $15.7 million or $0.25 per Mcfe for the same period in 2019. The increase in costs is due to higher labor and compression costs, partially offset by lower salt water disposal costs while the increase on a per Mcfe basis is due to the lower production volumes.
SilverBow's cash general and administrative costs were $14.4 million (a non-GAAP financial measure calculated as $17.9 million in net general and administrative costs less $3.5 million of share-based compensation) for the first nine months of 2020, or $0.29 per Mcfe, compared to $14.0 million (a non-GAAP financial measure calculated as $19.1 million in net general and administrative costs less $5.1 million of share-based compensation), or $0.22 per Mcfe, for the nine months ended September 30, 2019. In September, the Company implemented corporate cost reduction initiatives. On a go forward basis SilverBow expects to save approximately $2.5 million in annualized general and administrative costs.
28
Liquidity and Capital Resources
SilverBow's primary use of cash has been to fund capital expenditures to develop its oil and gas properties and to repay Credit Facility borrowings. As of September 30, 2020, the Company’s liquidity consisted of $1.2 million of cash-on-hand and $77.0 million in available borrowings on its Credit Facility, which had a $330 million borrowing base as of such date prior to the November 2, 2020 redetermination to $310 million. Management believes the Company has sufficient liquidity to meet its obligations through the fourth quarter of 2021 and execute its long-term development plans. See Note 6 to SilverBow's condensed consolidated financial statements for more information on its Credit Facility.
Contractual Commitments and Obligations
There were no other material changes in SilverBow's contractual commitments during the nine months ended September 30, 2020 from amounts referenced under “Contractual Commitments and Obligations” in Management's Discussion and Analysis of Financial Condition and Results of Operations in our Annual Report on Form 10-K for the year ended December 31, 2019.
Off-Balance Sheet Arrangements
As of September 30, 2020, the Company had no off-balance sheet arrangements requiring disclosure pursuant to Item 303(a) of Regulation S-K.
29
Summary of 2020 Financial Results Through September 30, 2020
•Revenues and Net Income (Loss): The Company's oil and gas revenues were $123.9 million for the nine months ended September 30, 2020, compared to $218.8 million for the nine months ended September 30, 2019. Revenues were lower primarily due to overall lower commodity pricing and production. The Company's net loss was $318.7 million for the nine months ended September 30, 2020, compared to net income of $108.4 million for the nine months ended September 30, 2019. The decrease in net income was primarily due to the non-cash impairment write-down, on a pre-tax basis, of $355.9 million on our oil and natural gas properties.
•Capital Expenditures: The Company's capital expenditures on an accrual basis were $75.7 million for the nine months ended September 30, 2020 compared to $207.4 million for the nine months ended September 30, 2019. The expenditures for the nine months ended September 30, 2020 and 2019 were attributable to drilling and completion activity.
•Working Capital: The Company had a working capital deficit of $7.8 million at September 30, 2020 and a working capital deficit of $27.8 million at December 31, 2019. The working capital computation does not include available liquidity through our Credit Facility.
•Cash Flows: For the nine months ended September 30, 2020, the Company generated cash from operating activities of $127.8 million, of which $2.4 million was attributable to changes in working capital. Cash used for property additions was $102.7 million. This included $25.6 million attributable to a net decrease of capital-related payables and accrued costs. Additionally, $0.4 million was paid during the nine months ended September 30, 2020, for property abandonment obligations related to the sale of our former Bay De Chene field. The Company’s net repayments on the Credit Facility were $26.0 million during the nine months ended September 30, 2020.
For the nine months ended September 30, 2019, the Company generated cash from operating activities of $153.1 million, of which $4.8 million was attributable to changes in working capital. Cash used for property additions was $234.9 million. This included $27.9 million attributable to a net decrease of capital-related payables and accrued costs. Additionally, $4.4 million was paid during the nine months ended September 30, 2019 for property abandonment obligations related to the sale of our former Bay De Chene field. The Company’s net borrowings on the Credit Facility were $87.0 million during the nine months ended September 30, 2019.
30
Results of Operations
Revenues — Three Months Ended September 30, 2020 and Three Months Ended September 30, 2019
Natural gas production was 71% and 72% of the Company's production volumes for the three months ended September 30, 2020 and 2019, respectively. Natural gas sales were 51% and 52% of oil and gas sales for the three months ended September 30, 2020 and 2019, respectively.
Crude oil production was 17% and 14% of the Company's production volumes for the three months ended September 30, 2020 and 2019, respectively. Crude oil sales were 39% and 40% of oil and gas sales for the three months ended September 30, 2020 and 2019, respectively.
NGL production was 12% and 14% of the Company's production volumes for the three months ended September 30, 2020 and 2019, respectively. NGL sales were 10% and 8% of oil and gas sales for the three months ended September 30, 2020 and 2019, respectively.
The following table provides additional information regarding the Company's oil and gas sales, by area, excluding any effects of the Company's hedging activities, for the three months ended September 30, 2020 and 2019:
| Fields | Three Months Ended September 30, 2020 | Three Months Ended September 30, 2019 | ||||||||||||||||||
|
Oil and Gas Sales
(In Millions) |
Net Oil and Gas Production
Volumes (MMcfe) |
Oil and Gas Sales
(In Millions) |
Net Oil and Gas Production
Volumes (MMcfe) |
|||||||||||||||||
| Artesia Wells | $ | 11.8 | 3,802 | $ | 23.8 | 6,182 | ||||||||||||||
| AWP | 15.3 | 3,659 | 19.5 | 4,026 | ||||||||||||||||
| Fasken | 13.0 | 6,500 | 21.6 | 9,244 | ||||||||||||||||
|
Other (1)
|
5.6 | 2,848 | 7.1 | 2,582 | ||||||||||||||||
| Total | $ | 45.7 | 16,809 | $ | 72.0 | 22,034 | ||||||||||||||
(1) Primarily composed of the Company's Rio Bravo, Oro Grande and Uno Mas fields.
The sales volumes decrease from 2019 to 2020 was primarily due to decreased production as a result of curtailed production volumes.
In the third quarter of 2020, our $26.3 million, or 37%, decrease in oil, NGL and natural gas sales from the prior year period resulted from:
•Price variances that had an approximately $13.0 million unfavorable impact on sales due to lower oil and natural gas pricing; and
•Volume variances that had an approximately $13.3 million unfavorable impact on sales due to overall decreased commodity production.
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The following table provides additional information regarding our oil and gas sales, by commodity type, as well as the effects of our hedging activities for derivative contracts held to settlement, for the three months ended September 30, 2020 and 2019 (in thousands, except per-dollar amounts):
| Three Months Ended September 30, 2020 | Three Months Ended September 30, 2019 | ||||||||||
| Production volumes: | |||||||||||
|
Oil (MBbl) (1)
|
472 | 506 | |||||||||
| Natural gas (MMcf) | 11,897 | 15,958 | |||||||||
|
Natural gas liquids (MBbl) (1)
|
347 | 507 | |||||||||
| Total (MMcfe) | 16,809 | 22,034 | |||||||||
| Oil, natural gas and natural gas liquids sales: | |||||||||||
| Oil | $ | 17,665 | $ | 28,894 | |||||||
| Natural gas | 23,595 | 37,040 | |||||||||
| Natural gas liquids | 4,439 | 6,080 | |||||||||
| Total | $ | 45,699 | $ | 72,014 | |||||||
| Average realized price: | |||||||||||
| Oil (per Bbl) | $ | 37.45 | $ | 57.14 | |||||||
| Natural gas (per Mcf) | 1.98 | 2.32 | |||||||||
| Natural gas liquids (per Bbl) | 12.79 | 11.99 | |||||||||
| Average per Mcfe | $ | 2.72 | $ | 3.27 | |||||||
| Price impact of cash-settled derivatives: | |||||||||||
| Oil (per Bbl) | $ | 6.91 | $ | 2.39 | |||||||
| Natural gas (per Mcf) | 0.39 | 0.51 | |||||||||
| Natural gas liquids (per Bbl) | (0.01) | 4.14 | |||||||||
| Average per Mcfe | $ | 0.47 | $ | 0.52 | |||||||
| Average realized price including impact of cash-settled derivatives: | |||||||||||
| Oil (per Bbl) | $ | 44.36 | $ | 59.53 | |||||||
| Natural gas (per Mcf) | 2.37 | 2.83 | |||||||||
| Natural gas liquids (per Bbl) | 12.78 | 16.14 | |||||||||
| Average per Mcfe | $ | 3.19 | $ | 3.79 | |||||||
(1) Oil and natural gas liquids are converted at the rate of one barrel to six Mcfe. Mcf refers to one thousand cubic feet, and MMcf refers to one million cubic feet. Bbl refers to one barrel of oil, and MBbl refers to one thousand barrels.
For the three months ended September 30, 2020 and 2019, the Company recorded net losses of $12.9 million and net gains of $13.4 million from our derivatives activities, respectively. Hedging activity is recorded in “Gain (loss) on commodity derivatives, net” on the accompanying condensed consolidated statements of operations.
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Costs and Expenses — Three Months Ended September 30, 2020 and Three Months Ended September 30, 2019
The following table provides additional information regarding our expenses for the three months ended September 30, 2020 and 2019:
| Costs and Expenses | Three Months Ended September 30, 2020 | Three Months Ended September 30, 2019 | ||||||
| General and administrative, net | $ | 5,833 | $ | 6,247 | ||||
| Depreciation, depletion, and amortization | 13,975 | 24,937 | ||||||
| Accretion of asset retirement obligations | 90 | 88 | ||||||
| Lease operating cost | 5,211 | 5,507 | ||||||
| Workovers | 8 | 93 | ||||||
| Transportation and gas processing | 5,094 | 6,782 | ||||||
| Severance and other taxes | 2,512 | 3,778 | ||||||
| Interest expense, net | 7,444 | 9,435 | ||||||
General and Administrative Expenses, Net. These expenses on a per-Mcfe basis were $0.35 and $0.28 for the three months ended September 30, 2020 and 2019, respectively. The increase per Mcfe was due to lower production while the decrease in costs was primarily due to lower salaries and burdens, lower share-based compensation and lower temporary labor fees. Included in general and administrative expenses is $1.1 million and $1.8 million in share-based compensation for the three months ended September 30, 2020 and 2019, respectively.
Depreciation, Depletion and Amortization. These expenses on a per-Mcfe basis were $0.83 and $1.13 for the three months ended September 30, 2020 and 2019, respectively. The decrease on a per Mcfe basis was driven by reductions to our depletable base due to non-cash impairment write-downs during the year.
Lease Operating Cost and Workovers. These expenses on a per-Mcfe basis were $0.31 and $0.25 for the three months ended September 30, 2020 and 2019, respectively. The increase per Mcfe was due to lower production.
Transportation and Gas Processing. These expenses are related to natural gas and NGL sales. These expenses on a per-Mcfe basis were $0.30 and $0.31 for the three months ended September 30, 2020 and 2019, respectively.
Severance and Other Taxes. These expenses on a per-Mcfe basis were $0.15 and $0.17 for the three months ended September 30, 2020 and 2019, respectively. Severance and other taxes, as a percentage of oil and gas sales, were approximately 5.5% and 5.2% for the three months ended September 30, 2020 and 2019, respectively.
Interest. Our gross interest cost was $7.4 million and $9.4 million for the three months ended September 30, 2020 and 2019, respectively. The decrease in gross interest cost is primarily due to decreased borrowings and lower interest rates. There were no capitalized interest costs for both the three months ended September 30, 2020 and 2019.
Income Taxes. The Company recorded an income tax benefit of $0.6 million and an income tax provision of $1.0 million for the three months ended September 30, 2020 and 2019, respectively. During the quarter ended June 30, 2020, management had determined that it was not more likely than not that the Company would realize future cash benefits from its remaining federal carryover items and other deferred tax assets and, accordingly, recorded a full valuation allowance to offset its net deferred tax assets in excess of deferred tax liabilities. Our income tax benefit for the three months ended September 30, 2020 is fully attributable to a current state income tax benefit.
33
Revenues — Nine Months Ended September 30, 2020 and Nine Months Ended September 30, 2019
Natural gas production was 77% of the Company's production volumes for both the nine months ended September 30, 2020 and 2019. Natural gas sales were 59% and 60% of oil and gas sales for the nine months ended September 30, 2020 and 2019, respectively.
Crude oil production was 13% and 11% of the Company's production volumes for the nine months ended September 30, 2020 and 2019, respectively. Crude oil sales were 33% and 31% of oil and gas sales for the nine months ended September 30, 2020 and 2019, respectively.
NGL production was 10% and 12% of the Company's production volumes for the nine months ended September 30, 2020 and 2019, respectively. NGL sales were 8% and 9% of oil and gas sales for the nine months ended September 30, 2020 and 2019, respectively.
The following table provides additional information regarding the Company's oil and gas sales, by area, excluding any effects of the Company's hedging activities, for the nine months ended September 30, 2020 and 2019:
| Fields | Nine Months Ended September 30, 2020 | Nine Months Ended September 30, 2019 | ||||||||||||||||||
|
Oil and Gas Sales
(In Millions) |
Net Oil and Gas Production
Volumes (MMcfe) |
Oil and Gas Sales
(In Millions) |
Net Oil and Gas Production
Volumes (MMcfe) |
|||||||||||||||||
| Artesia Wells | $ | 30.6 | 10,016 | $ | 56.8 | 14,067 | ||||||||||||||
| AWP | 33.9 | 8,872 | 57.0 | 11,153 | ||||||||||||||||
| Fasken | 44.2 | 23,676 | 68.5 | 25,061 | ||||||||||||||||
|
Other (1)
|
15.2 | 7,904 | 36.5 | 12,497 | ||||||||||||||||
| Total | $ | 123.9 | 50,468 | $ | 218.8 | 62,778 | ||||||||||||||
(1) Primarily composed of the Company's Rio Bravo, Oro Grande and Uno Mas fields.
The sales volumes decrease from 2019 to 2020 was primarily due to decreased production as a result of curtailed production volumes.
In the nine months ended September 30, 2020, our $94.9 million, or 43%, decrease in oil, NGL and natural gas sales from the prior year period resulted from:
•Price variances that had an approximately $58.8 million unfavorable impact on sales due to overall lower commodity pricing; and
•Volume variances that had an approximately $36.1 million unfavorable impact on sales due to overall decreased commodity production due to curtailed volumes during the year.
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The following table provides additional information regarding our oil and gas sales, by commodity type, as well as the effects of our hedging activities for derivative contracts held to settlement, for the nine months ended September 30, 2020 and 2019 (in thousands, except per-dollar amounts):
| Nine Months Ended September 30, 2020 | Nine Months Ended September 30, 2019 | ||||||||||
| Production volumes: | |||||||||||
|
Oil (MBbl) (1)
|
1,093 | 1,167 | |||||||||
| Natural gas (MMcf) | 39,018 | 48,274 | |||||||||
|
Natural gas liquids (MBbl) (1)
|
815 | 1,250 | |||||||||
| Total (MMcfe) | 50,468 | 62,778 | |||||||||
| Oil, natural gas and natural gas liquids sales: | |||||||||||
| Oil | $ | 40,979 | $ | 68,441 | |||||||
| Natural gas | 73,170 | 131,941 | |||||||||
| Natural gas liquids | 9,772 | 18,400 | |||||||||
| Total | $ | 123,921 | $ | 218,781 | |||||||
| Average realized price: | |||||||||||
| Oil (per Bbl) | $ | 37.48 | $ | 58.65 | |||||||
| Natural gas (per Mcf) | 1.88 | 2.73 | |||||||||
| Natural gas liquids (per Bbl) | 11.99 | 14.72 | |||||||||
| Average per Mcfe | $ | 2.46 | $ | 3.49 | |||||||
| Price impact of cash-settled derivatives: | |||||||||||
| Oil (per Bbl) | $ | 17.05 | $ | 0.93 | |||||||
| Natural gas (per Mcf) | 0.50 | 0.23 | |||||||||
| Natural gas liquids (per Bbl) | — | 3.66 | |||||||||
| Average per Mcfe | $ | 0.76 | $ | 0.27 | |||||||
| Average realized price including impact of cash-settled derivatives: | |||||||||||
| Oil (per Bbl) | $ | 54.54 | $ | 59.58 | |||||||
| Natural gas (per Mcf) | 2.38 | 2.96 | |||||||||
| Natural gas liquids (per Bbl) | 11.99 | 18.38 | |||||||||
| Average per Mcfe | $ | 3.22 | $ | 3.76 | |||||||
(1) Oil and natural gas liquids are converted at the rate of one barrel to six Mcfe. Mcf refers to one thousand cubic feet, and MMcf refers to one million cubic feet. Bbl refers to one barrel of oil, and MBbl refers to one thousand barrels.
For the nine months ended September 30, 2020 and 2019, the Company recorded net gains of $66.9 million and $34.3 million from our derivatives activities, respectively. Included in our net gain during the nine months ended September 30, 2020 was $38.3 million for monetized derivative contracts received in the first quarter of 2020. Hedging activity is recorded in “Gain (loss) on commodity derivatives, net” on the accompanying condensed consolidated statements of operations.
35
Costs and Expenses — Nine Months Ended September 30, 2020 and Nine Months Ended September 30, 2019
The following table provides additional information regarding our expenses for the nine months ended September 30, 2020 and 2019:
| Costs and Expenses | Nine Months Ended September 30, 2020 | Nine Months Ended September 30, 2019 | ||||||
| General and administrative, net | $ | 17,926 | $ | 19,146 | ||||
| Depreciation, depletion, and amortization | 51,130 | 70,771 | ||||||
| Accretion of asset retirement obligations | 263 | 257 | ||||||
| Lease operating cost | 16,023 | 15,074 | ||||||
| Workovers | 8 | 613 | ||||||
| Transportation and gas processing | 16,291 | 19,917 | ||||||
| Severance and other taxes | 7,513 | 11,044 | ||||||
| Interest expense, net | 23,876 | 27,500 | ||||||
| Write-down of oil and gas properties | 355,948 | — | ||||||
General and Administrative Expenses, Net. These expenses on a per-Mcfe basis were $0.36 and $0.30 for the nine months ended September 30, 2020 and 2019, respectively. The increase per Mcfe was due to lower production while the decrease in costs was primarily due to lower salaries and burdens, lower share-based compensation and lower temporary labor fees. Included in general and administrative expenses is $3.5 million and $5.1 million in share-based compensation for the nine months ended September 30, 2020 and 2019, respectively.
Depreciation, Depletion and Amortization. These expenses on a per-Mcfe basis were $1.01 and $1.13 for the nine months ended September 30, 2020 and 2019, respectively. The decrease on a per Mcfe basis was driven by reductions to our depletable base due to non-cash impairment write-downs during the year.
Lease Operating Cost and Workovers. These expenses on a per-Mcfe basis were $0.32 and $0.25 for the nine months ended September 30, 2020 and 2019, respectively. The increase per Mcfe was due to lower production while the increase in costs is due to higher labor and compression costs, partially offset by lower salt water disposal costs.
Transportation and Gas Processing. These expenses are related to natural gas and NGL sales. These expenses on a per-Mcfe basis were $0.32 for both the nine months ended September 30, 2020 and 2019.
Severance and Other Taxes. These expenses on a per-Mcfe basis were $0.15 and $0.18 for the nine months ended September 30, 2020 and 2019, respectively. Severance and other taxes, as a percentage of oil and gas sales, were approximately 6.1% and 5.0% for the nine months ended September 30, 2020 and 2019, respectively.
Interest. Our gross interest cost was $23.9 million and $27.7 million for the nine months ended September 30, 2020 and 2019, respectively. The decrease in gross interest cost is primarily due to decreased borrowings and lower interest rates. There was no capitalized interest cost and $0.2 million of capitalized interest for the nine months ended September 30, 2020 and 2019, respectively.
Write-down of oil and gas properties. Due to the effects of pricing and timing of projects, for the nine months ended September 30, 2020, we reported a non-cash impairment write-down, on a pre-tax basis, of $355.9 million on our oil and natural gas properties. These impairments occurred in the first half of 2020. There was no impairment for the nine months ended September 30, 2019.
Income Taxes. In March and April 2020, the COVID-19 pandemic caused volatility in the market price for crude oil due to the disruption of global supply and demand. In response to these market conditions and given the decline in oil prices and economic outlook for our Company, during the quarter ended June 30, 2020, management determined that it was not more likely than not that the Company would realize future cash benefits from its remaining federal carryover items and other deferred tax assets and, accordingly, recorded a full valuation allowance as a discrete item in the second quarter to offset its net deferred tax assets in excess of deferred tax liabilities. This resulted in tax expenses of $21.2 million in the second quarter of 2020. Our income tax provision of $20.6 million for the nine months ended September 30, 2020 is inclusive of a current state income tax benefit of $0.6 million. For the nine months ended September 30, 2019, the Company was able to complete several
36
operational initiatives that resulted in increased production, lower development costs and expanded inventory of development prospects. The results of these initiatives led management to determine, after weighing both positive and negative evidence, that the Company will more likely than not be able to realize the benefits of its deferred tax assets. Accordingly, we released the valuation allowance in the second quarter of 2019, resulting in a net deferred tax benefit of $19.5 million for the nine months ended September 30, 2019.
37
Critical Accounting Policies and New Accounting Pronouncements
There have been no changes in the critical accounting policies disclosed in our 2019 Annual Report on Form 10-K.
Forward-Looking Statements
This report includes forward-looking statements intended to qualify for the safe harbors from liability established by the Private Securities Litigation Reform Act of 1995, Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended (the "Exchange Act"). These forward-looking statements are subject to a number of risks and uncertainties, many of which are beyond our control. All statements, other than statements of historical fact included in this report, regarding our strategy, future operations, financial position, estimated production levels, expected oil and natural gas pricing, estimated oil and natural gas reserves or the present value thereof, reserve increases, capital expenditures, budget, projected costs, prospects, plans and objectives of management are forward-looking statements. When used in this report, the words “could,” “believe,” “anticipate,” “intend,” “estimate,” “budgeted,” “expect,” “may,” “continue,” “predict,” “potential,” “project” and similar expressions are intended to identify forward-looking statements, although not all forward-looking statements contain such identifying words.
Important factors that could cause actual results to differ materially from our expectations include, but are not limited to, the following risks and uncertainties:
• the severity and duration of world health events, including the COVID-19 pandemic, related economic repercussions and the resulting severe disruption in the oil and gas industry and negative impact on demand for oil and gas, which is negatively impacting our business;
• the current significant surplus in the supply of oil and actions by the members of the Organization of the Petroleum Exporting Countries (“OPEC”) and Russia (together with OPEC and other allied producing countries, “OPEC+”) with respect to oil production levels and announcements of potential changes in such levels, including the ability of the OPEC+ countries to agree on and comply with supply limitations;
• operational challenges relating to the COVID-19 pandemic and efforts to mitigate the spread of the virus, including logistical challenges, protecting the health and well-being of our employees, remote work arrangements, performance of contracts and supply chain disruptions;
• shut-in and curtailment of production due to decreases in available storage capacity or other factors;
• volatility in natural gas, oil and NGL prices;
• future cash flows and their adequacy to maintain our ongoing operations;
• liquidity, including our ability to satisfy our short- or long-term liquidity needs;
• our borrowing capacity, future covenant compliance, cash flows and liquidity;
• operating results;
• asset disposition efforts or the timing or outcome thereof;
• ongoing and prospective joint ventures, their structure and substance, and the likelihood of their finalization or the timing thereof;
• the amount, nature and timing of capital expenditures, including future development costs;
• timing, cost and amount of future production of oil and natural gas;
• availability of drilling and production equipment or availability of oil field labor;
• availability, cost and terms of capital;
• drilling of wells;
• availability and cost for transportation of oil and natural gas;
• costs of exploiting and developing our properties and conducting other operations;
• competition in the oil and natural gas industry;
• general economic conditions;
• opportunities to monetize assets;
• effectiveness of our risk management activities;
• environmental liabilities;
• counterparty credit risk;
38
• governmental regulation and taxation of the oil and natural gas industry;
• developments in world oil and gas markets and in oil and natural gas-producing countries;
• uncertainty regarding our future operating results; and
• other risks and uncertainties described in Item 1A. “Risk Factors” in this Quarterly Report on Form 10-Q, our Annual Report on Form 10-K for the year ended December 31, 2019 and our Quarterly Reports on Form 10-Q for the quarters ended March 31, 2020 and June 30, 2020.
Many of the foregoing risks and uncertainties are, and will be, exacerbated by the COVID-19 pandemic and any consequent worsening of the global business and economic environment. New factors emerge from time to time, and it is not possible for us to predict all such factors. Should one or more of the risks or uncertainties described in this Quarterly Report occur, or should underlying assumptions prove incorrect, actual results and plans could differ materially from those expressed in any forward-looking statements.
All forward-looking statements speak only as of the date they are made. You should not place undue reliance on these forward-looking statements. Although we believe that our plans, intentions and expectations reflected in or suggested by the forward-looking statements we make in this report are reasonable, we can give no assurance that these plans, intentions or expectations will be achieved. We disclose important factors that could cause our actual results to differ materially from our expectations under "Risk Factors" in Item 1A of our Annual Report on Form 10-K for the year ended December 31, 2019 and in subsequent Quarterly Reports on Form 10-Q and Current Reports on Form 8-K. These cautionary statements qualify all forward-looking statements attributable to us or persons acting on our behalf.
All subsequent written and oral forward-looking statements attributable to us or to persons acting on our behalf are expressly qualified in their entirety by the foregoing. We undertake no obligation to publicly release the results of any revisions to any such forward-looking statements that may be made to reflect events or circumstances after the date of this report or to reflect the occurrence of unanticipated events.
39
Item 3. Quantitative and Qualitative Disclosures About Market Risk
Commodity Risk. Our major market risk exposure is the commodity pricing applicable to our oil and natural gas production. Realized commodity prices received for such production are primarily driven by the prevailing worldwide price for crude oil and spot prices applicable to natural gas. This commodity pricing volatility has continued with unpredictable price swings in recent periods.
Our price risk management policy permits the utilization of agreements and financial instruments (such as futures, forward contracts, swaps and options contracts) to mitigate price risk associated with fluctuations in oil and natural gas prices. We do not utilize these agreements and financial instruments for trading and only enter into derivative agreements with banks in our Credit Facility. For additional discussion related to our price risk management policy, refer to Note 8 of our condensed consolidated financial statements included in Item 1 of this report.
Customer Credit Risk. We are exposed to the risk of financial non-performance by customers. Our ability to collect on sales to our customers is dependent on the liquidity of our customer base. Continued volatility in both credit and commodity markets may reduce the liquidity of our customer base. To manage customer credit risk, we monitor credit ratings of customers and, when considered necessary, we also obtain letters of credit from certain customers, parent company guarantees if applicable, and other collateral as considered necessary to reduce risk of loss. Due to availability of other purchasers, we do not believe the loss of any single oil or natural gas customer would have a material adverse effect on our results of operations.
Concentration of Sales Risk. A large portion of our oil and gas sales are made to Kinder Morgan, Inc. and its affiliates and we expect to continue this relationship in the future. We believe that the business risk of this relationship is mitigated by the reputation and nature of their business and the availability of other purchasers.
Interest Rate Risk. At September 30, 2020, we had a combined $453.0 million drawn under our Credit Facility and our Second Lien, which bear floating rates of interest and therefore are susceptible to interest rate fluctuations. These variable interest rate borrowings are also impacted by changes in short-term interest rates. A hypothetical one percentage point increase in interest rates on our borrowings outstanding under our Credit Facility and Second Lien at September 30, 2020 would increase our annual interest expense by $4.5 million.
40
Item 4. Controls and Procedures
Disclosure Controls and Procedures
We maintain disclosure controls and procedures, as defined in Rules 13a-15(e) and 15d-15(e) of the Exchange Act, consisting of controls and other procedures designed to give reasonable assurance that information we are required to disclose in the reports we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the Securities and Exchange Commission’s rules and forms and that such information is accumulated and communicated to management, including our Chief Executive Officer and our Chief Financial Officer, to allow timely decisions regarding such required disclosure. Our Chief Executive Officer and Chief Financial Officer have evaluated such disclosure controls and procedures as of the end of the period covered by this quarterly report on Form 10-Q and have determined that such disclosure controls and procedures are effective.
Changes in Internal Control Over Financial Reporting
There was no change in our internal control over financial reporting during the three months ended September 30, 2020 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.
41
PART II. OTHER INFORMATION
Item 1. Legal Proceedings.
No material legal proceedings are pending other than ordinary, routine litigation incidental to the Company’s business.
Item 1A. Risk Factors.
A description of our risk factors can be found in “Item 1A. Risk Factors” included in our Annual Report on Form 10-K for the fiscal year ended December 31, 2019 and in subsequent Quarterly Reports on Form 10-Q. Other than as provided below, there were no material changes to those risk factors during the nine months ended September 30, 2020.
An imbalance between the supply of and demand for oil and natural gas has caused and may continue to cause extreme market volatility and may result in increased costs and decreased availability of storage capacity. The lack of a market or available storage for certain of our products could cause interruptions in our operations, including temporary curtailments or shut-ins, which could adversely affect our financial condition and results of operations.
The marketing of our natural gas and oil production is substantially dependent upon the existence of adequate markets for our products. In response to the COVID-19 pandemic, governments have tried to slow the spread of the virus by imposing social distancing guidelines, travel restrictions and stay-at-home orders, which have caused a significant decrease in the demand for natural gas and oil. The imbalance between the supply of and demand for these products, as well as the uncertainty around the extent and timing of an economic recovery, have caused extreme market volatility and a substantial adverse effect on commodity prices in March and April and may continue to cause market volatility and adverse effects on commodity prices. Also as a result of this imbalance, the industry experienced storage capacity constraints with respect to certain natural gas products and oil. In the event we are unable to sell our production or enter into additional storage arrangements on commercially reasonable terms or at all, we could be forced to temporarily shut in a portion of our production or delay or discontinue drilling plans and commercial production following a discovery of hydrocarbons. Although our production is more heavily weighted to natural gas, the lack of a market or available storage for any one natural gas product or oil could result in us temporarily curtailing or shutting in such production as we may be unable to curtail the production of individual products in a meaningful way without reducing the production of other products. Any such shut-in or curtailment, or any inability to obtain favorable terms for delivery of the natural gas and oil we produce, could adversely affect our financial condition and results of operations.
A pandemic, epidemic or outbreak of an infectious disease, such as COVID-19, may materially adversely affect our business.
The global or national outbreak of an infectious disease, such as COVID-19, may cause disruptions to our business and operational plans, which may include (i) shortages of employees, (ii) unavailability of contractors and subcontractors, (iii) interruption of supplies from third parties upon which we rely, (iv) recommendations of, or restrictions imposed by, government and health authorities, including quarantines, to address the COVID-19 pandemic and (v) restrictions that we and our contractors and subcontractors impose, including facility shutdowns, to ensure the safety of employees and others. While it is not possible to predict their extent or duration, these disruptions may have a material adverse effect on our business, financial condition and results of operations.
Further, the effects of COVID-19 and concerns regarding its global spread have negatively impacted domestic and international demand for crude oil and natural gas, which has contributed and could continue to contribute to price volatility, could impact the price we receive for natural gas and oil and could materially and adversely affect the demand for and marketability of our production, as well as lead to temporary curtailment of production due to lack of downstream demand or storage capacity. Additionally, to the extent the COVID-19 pandemic adversely affects our business and financial results, it may also have the effect of heightening many of the other risks set forth in “Item 1A. Risk Factors” in our Annual Report on Form 10-K for the year ended December 31, 2019.
As domestic demand for crude oil has declined substantially due to the COVID-19 pandemic, we cannot ensure that there will be a physical market for our production at economic prices until markets stabilize.
As a result of low commodity prices or a future decrease in commodity prices, we did temporarily curtail and may curtail again in the future a portion of our estimated oil production and/or may store rather than sell additional crude oil
42
production in the near future. The excess supply of oil could lead to potential curtailments by our purchasers. While we believe that any potential shutting-in of such production will not impact the productivity of such wells when reopened, there is no assurance we will not have a degradation in well performance upon returning those wells to production. The storing or shutting in of a portion of our production could potentially also result in increased costs under our midstream and other contracts. Any of the foregoing could result in an adverse impact on our revenues, financial position and cash flows.
A financial crisis may impact our business, financial condition and cash flows and may adversely impact our ability to obtain funding.
We use our cash flows from operating activities and borrowings to fund our capital expenditures, and we rely on the capital markets and asset monetization transactions to provide us with additional capital for large or exceptional transactions. However, the COVID-19 pandemic and the public and political responses thereto have contributed to equity market volatility and the potential risk of a global recession, and we expect this global equity market volatility to continue at least until the pandemic of COVID-19 stabilizes, if not longer. As such, we may not be able to access adequate funding, including due to an unwillingness or inability on the part of our lending counterparties to meet their funding obligations. We may also face limitations on our ability to access the debt and equity capital markets and complete asset sales, increased counterparty credit risk on derivatives contracts, and requirements by our contractual counterparties to post collateral guaranteeing performance.
The unavailability or high cost of drilling rigs, equipment, supplies, personnel, water disposal and oilfield services could adversely affect our ability to execute on a timely basis our exploration and development plans within our budget and operate profitably.
Shortages or the high cost of drilling rigs, equipment, supplies or personnel, including shortages or unavailability of personnel, supplies and equipment arising from the COVID-19 pandemic could delay or adversely affect our development and exploration operations. If the price of oil and natural gas increases, the demand for production equipment and personnel will likely also increase, potentially resulting in shortages of equipment and personnel. In addition, larger producers may be more likely to secure access to such equipment by offering drilling companies more lucrative terms. If we are unable to acquire access to such resources, or can obtain access only at higher prices, this would potentially delay our ability to convert our reserves into cash flow and could also significantly increase the cost of producing those reserves, thereby negatively impacting anticipated net income.
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds.
None.
Item 3. Defaults Upon Senior Securities.
Not applicable.
Item 4. Mine Safety Disclosures.
Not applicable.
Item 5. Other Information.
None.
43
Item 6. Exhibits.
The following exhibits in this index are required by Item 601 of Regulation S-K and are filed herewith or are incorporated herein by reference:
| 3.1 | |||||
| 3.2 | |||||
| 10.1* | |||||
| 31.1* | |||||
| 31.2* | |||||
| 32.1# | |||||
| 101* | The following materials from SilverBow Resources, Inc.'s Quarterly Report on Form 10-Q for the quarter ended September 30, 2020 formatted in iXBRL (Inline eXtensible Business Reporting Language): (i) the Condensed Consolidated Balance Sheets (Unaudited), (ii) the Condensed Consolidated Statements of Operations (Unaudited), (iii) the Consolidated Statements of Stockholders Equity (Unaudited), (iv) the Condensed Consolidated Statements of Cash Flows (Unaudited), and (v) Notes to the Condensed Consolidated Financial Statements. | ||||
| 104 | Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101). | ||||
*Filed herewith
# Furnished herewith. Not considered to be "filed" for the purposes of Section 18 of the Securities Exchange Act of 1934 or otherwise subject to the liabilities of that section.
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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.
|
SILVERBOW RESOURCES, INC.
(Registrant) |
||||||||||||||
| Date: | November 5, 2020 | By: | /s/ Christopher M. Abundis | |||||||||||
|
Christopher M. Abundis
Executive Vice President, Chief Financial Officer, General Counsel and Secretary |
||||||||||||||
| Date: | November 5, 2020 | By: | /s/ W. Eric Schultz | |||||||||||
|
W. Eric Schultz
Controller |
||||||||||||||
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