CIVITAS RESOURCES, INC. - Quarter Report: 2020 March (Form 10-Q)
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
☒ QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
For the quarterly period ended March 31, 2020
or
☐ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
Commission File Number: 001-35371
Bonanza Creek Energy, Inc.
(Exact name of registrant as specified in its charter)
| Delaware | 61-1630631 | |||||||
| (State or other jurisdiction of incorporation or organization) | (I.R.S. Employer Identification No.) | |||||||
| 410 17th Street, | Suite 1400 | ||||||||||
| Denver, | Colorado | 80202 | |||||||||
| (Address of principal executive offices) | (Zip Code) | ||||||||||
(720) 440-6100
(Registrant’s telephone number, including area code)
| Securities registered pursuant to Section 12(b) of the Act: | ||||||||
| Title of each class | Trading Symbol | Name of exchange on which registered | ||||||
| Common Stock, par value $0.01 per share | BCEI | 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 ☐ No
Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). ☒ Yes ☐ No
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer”, “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.
| Large Accelerated Filer | ☐ | Accelerated Filer | ☒ | ||||||||||||||
| Non-accelerated Filer | ☐ | ||||||||||||||||
| Emerging growth company | ☐ | Smaller reporting company | ☐ | ||||||||||||||
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). ☐ Yes ☒ No
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 ☐ No
As of May 4, 2020, the registrant had 20,772,904 shares of common stock outstanding.
BONANZA CREEK ENERGY, INC.
INDEX
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PART I - FINANCIAL INFORMATION
Item 1. Financial Statements.
BONANZA CREEK ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS (UNAUDITED)
(in thousands, except share amounts)
| March 31, 2020 | December 31, 2019 | ||||||||||
| ASSETS | |||||||||||
| Current assets: | |||||||||||
| Cash and cash equivalents | $ | 11,052 | $ | 11,008 | |||||||
| Accounts receivable, net: | |||||||||||
| Oil and gas sales | 16,463 | 43,714 | |||||||||
| Joint interest and other | 46,205 | 38,136 | |||||||||
| Prepaid expenses and other | 5,948 | 7,048 | |||||||||
| Inventory of oilfield equipment | 7,212 | 7,726 | |||||||||
| Derivative assets (note 10) | 77,973 | 2,884 | |||||||||
| Total current assets | 164,853 | 110,516 | |||||||||
Property and equipment (successful efforts method): | |||||||||||
| Proved properties | 983,609 | 935,025 | |||||||||
| Less: accumulated depreciation, depletion, and amortization | (147,790) | (126,614) | |||||||||
| Total proved properties, net | 835,819 | 808,411 | |||||||||
| Unproved properties | 113,247 | 143,020 | |||||||||
| Wells in progress | 90,508 | 98,750 | |||||||||
Other property and equipment, net of accumulated depreciation of $3,291 in 2020 and $3,142 in 2019 | 3,607 | 3,394 | |||||||||
| Total property and equipment, net | 1,043,181 | 1,053,575 | |||||||||
| Long-term derivative assets (note 10) | 12,578 | 121 | |||||||||
| Right-of-use assets (note 3) | 40,023 | 38,562 | |||||||||
| Other noncurrent assets | 3,434 | 3,544 | |||||||||
| Total assets | $ | 1,264,069 | $ | 1,206,318 | |||||||
| LIABILITIES AND STOCKHOLDERS’ EQUITY | |||||||||||
| Current liabilities: | |||||||||||
| Accounts payable and accrued expenses (note 4) | $ | 63,733 | $ | 57,638 | |||||||
| Oil and gas revenue distribution payable | 18,185 | 29,021 | |||||||||
| Lease liability (note 3) | 13,198 | 11,690 | |||||||||
| Derivative liability (note 10) | 1,248 | 6,390 | |||||||||
| Total current liabilities | 96,364 | 104,739 | |||||||||
| Long-term liabilities: | |||||||||||
| Credit facility (note 5) | 59,000 | 80,000 | |||||||||
| Lease liability (note 3) | 27,431 | 27,540 | |||||||||
| Ad valorem taxes | 37,029 | 28,520 | |||||||||
| Derivative liability (note 10) | 204 | 921 | |||||||||
| Asset retirement obligations for oil and gas properties (note 9) | 27,622 | 27,908 | |||||||||
| Total liabilities | 247,650 | 269,628 | |||||||||
| Commitments and contingencies (note 6) | |||||||||||
| Stockholders’ equity: | |||||||||||
Preferred stock, $0.01 par value, 25,000,000 shares authorized, none outstanding | — | — | |||||||||
Common stock, $0.01 par value, 225,000,000 shares authorized, 20,655,082 and 20,643,738 issued and outstanding as of March 31, 2020 and December 31, 2019, respectively | 4,284 | 4,284 | |||||||||
| Additional paid-in capital | 703,351 | 702,173 | |||||||||
| Retained earnings | 308,784 | 230,233 | |||||||||
| Total stockholders’ equity | 1,016,419 | 936,690 | |||||||||
| Total liabilities and stockholders’ equity | $ | 1,264,069 | $ | 1,206,318 | |||||||
The accompanying notes are an integral part of these condensed consolidated financial statements.
1
BONANZA CREEK ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME (LOSS) (UNAUDITED)
(in thousands, except per share amounts)
| Three Months Ended March 31, | |||||||||||
| 2020 | 2019 | ||||||||||
| Operating net revenues: | |||||||||||
| Oil and gas sales | $ | 60,405 | $ | 72,594 | |||||||
| Operating expenses: | |||||||||||
| Lease operating expense | 5,699 | 5,426 | |||||||||
| Midstream operating expense | 4,014 | 2,321 | |||||||||
| Gathering, transportation, and processing | 3,481 | 4,022 | |||||||||
| Severance and ad valorem taxes | 5,173 | 4,248 | |||||||||
| Exploration | 373 | 97 | |||||||||
| Depreciation, depletion, and amortization | 21,584 | 15,759 | |||||||||
| Abandonment and impairment of unproved properties | 30,057 | 879 | |||||||||
| Bad debt expense | 576 | — | |||||||||
General and administrative expense (including $1,239 and $1,380, respectively, of stock-based compensation) | 9,429 | 10,278 | |||||||||
| Total operating expenses | 80,386 | 43,030 | |||||||||
| Other income (expense): | |||||||||||
| Derivative gain (loss) | 100,419 | (36,544) | |||||||||
| Interest expense, net | (217) | (1,151) | |||||||||
| Gain on sale of properties, net | — | 1,126 | |||||||||
| Other income (expense) | (1,670) | 12 | |||||||||
| Total other income (expense) | 98,532 | (36,557) | |||||||||
| Income (loss) from operations before taxes | 78,551 | (6,993) | |||||||||
| Income tax benefit (expense) | — | — | |||||||||
| Net income (loss) | $ | 78,551 | $ | (6,993) | |||||||
| Comprehensive income (loss) | $ | 78,551 | $ | (6,993) | |||||||
| Net income (loss) per common share: | |||||||||||
| Basic | $ | 3.80 | $ | (0.34) | |||||||
| Diluted | $ | 3.80 | $ | (0.34) | |||||||
| Weighted-average common shares outstanding: | |||||||||||
| Basic | 20,649 | 20,557 | |||||||||
| Diluted | 20,684 | 20,557 | |||||||||
The accompanying notes are an integral part of these condensed consolidated financial statements.
2
BONANZA CREEK ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY (UNAUDITED)
(in thousands, except share amounts)
| Additional | |||||||||||||||||||||||||||||
| Common Stock | Paid-In | Retained | |||||||||||||||||||||||||||
| Shares | Amount | Capital | Earnings | Total | |||||||||||||||||||||||||
| Balances, December 31, 2019 | 20,643,738 | $ | 4,284 | $ | 702,173 | $ | 230,233 | $ | 936,690 | ||||||||||||||||||||
| Restricted common stock issued | 13,674 | — | — | — | — | ||||||||||||||||||||||||
| Stock used for tax withholdings | (2,330) | — | (61) | — | (61) | ||||||||||||||||||||||||
| Stock-based compensation | — | — | 1,239 | — | 1,239 | ||||||||||||||||||||||||
| Net income | — | — | — | 78,551 | 78,551 | ||||||||||||||||||||||||
| Balances, March 31, 2020 | 20,655,082 | $ | 4,284 | $ | 703,351 | $ | 308,784 | $ | 1,016,419 | ||||||||||||||||||||
| Balances, December 31, 2018 | 20,543,940 | $ | 4,286 | $ | 696,461 | $ | 163,166 | $ | 863,913 | ||||||||||||||||||||
| Restricted common stock issued | 20,687 | — | — | — | — | ||||||||||||||||||||||||
| Stock used for tax withholdings | (6,036) | — | (153) | — | (153) | ||||||||||||||||||||||||
| Stock-based compensation | — | — | 1,380 | — | 1,380 | ||||||||||||||||||||||||
| Net loss | — | — | — | (6,993) | (6,993) | ||||||||||||||||||||||||
| Balances, March 31, 2019 | 20,558,591 | $ | 4,286 | $ | 697,688 | $ | 156,173 | $ | 858,147 | ||||||||||||||||||||
The accompanying notes are an integral part of these condensed consolidated financial statements.
3
BONANZA CREEK ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(UNAUDITED)
(in thousands)
| Three months ended March 31, | |||||||||||
| 2020 | 2019 | ||||||||||
| Cash flows from operating activities: | |||||||||||
| Net income (loss) | $ | 78,551 | $ | (6,993) | |||||||
| Adjustments to reconcile net income (loss) to net cash provided by operating activities: | |||||||||||
| Depreciation, depletion, and amortization | 21,584 | 15,759 | |||||||||
| Abandonment and impairment of unproved properties | 30,057 | 879 | |||||||||
| Well abandonment costs and dry hole expense | (8) | 62 | |||||||||
| Stock-based compensation | 1,239 | 1,380 | |||||||||
| Non-cash lease component | (51) | — | |||||||||
| Amortization of deferred financing costs | 123 | 125 | |||||||||
| Derivative (gain) loss | (100,419) | 36,544 | |||||||||
| Derivative cash settlements | 11,254 | 936 | |||||||||
| Gain on sale of properties, net | — | (1,126) | |||||||||
| Other | (4,240) | (900) | |||||||||
| Changes in current assets and liabilities: | |||||||||||
| Accounts receivable, net | 19,182 | 6,237 | |||||||||
| Prepaid expenses and other assets | 1,100 | (440) | |||||||||
| Accounts payable and accrued liabilities | (9,768) | (10,150) | |||||||||
| Settlement of asset retirement obligations | (610) | (592) | |||||||||
| Net cash provided by operating activities | 47,994 | 41,721 | |||||||||
| Cash flows from investing activities: | |||||||||||
| Acquisition of oil and gas properties | (284) | (1,362) | |||||||||
| Exploration and development of oil and gas properties | (26,225) | (36,503) | |||||||||
| Proceeds from sale of oil and gas properties | — | 1,153 | |||||||||
| Additions to property and equipment - non oil and gas | (362) | (76) | |||||||||
| Net cash used in investing activities | (26,871) | (36,788) | |||||||||
| Cash flows from financing activities: | |||||||||||
| Proceeds from credit facility | 15,000 | 15,000 | |||||||||
| Payments to credit facility | (36,000) | — | |||||||||
| Payment of employee tax withholdings in exchange for the return of common stock | (61) | (153) | |||||||||
| Principal payments on finance lease obligations | (10) | — | |||||||||
| Net cash provided by (used in) financing activities | (21,071) | 14,847 | |||||||||
| Net change in cash, cash equivalents, and restricted cash | 52 | 19,780 | |||||||||
| Cash, cash equivalents, and restricted cash: | |||||||||||
| Beginning of period | 11,095 | 13,002 | |||||||||
| End of period | $ | 11,147 | $ | 32,782 | |||||||
Supplemental cash flow disclosure(1): | |||||||||||
| Cash paid for interest, net of capitalization | $ | 246 | $ | 661 | |||||||
| Changes in working capital related to drilling expenditures | $ | (13,532) | $ | (5,710) | |||||||
(1) Refer to Note 3 - Leases in the notes to the condensed consolidated financial statements for discussion of right-of-use assets obtained in exchange for lease liabilities. | |||||||||||
The accompanying notes are an integral part of these condensed consolidated financial statements.
4
BONANZA CREEK ENERGY, INC. AND SUBSIDIARIES
NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)
NOTE 1 - ORGANIZATION AND BUSINESS
Bonanza Creek Energy, Inc. (“BCEI” or, together with our consolidated subsidiaries, the “Company”) is engaged primarily in acquiring, developing, extracting, and producing oil and gas properties. The Company’s assets and operations are concentrated in the rural portions of the Wattenberg Field in Colorado.
NOTE 2 - BASIS OF PRESENTATION
These unaudited condensed consolidated financial statements have been prepared in accordance with U.S. generally accepted accounting principles (“GAAP”) for interim financial statements and pursuant to the rules and regulations of the Securities and Exchange Commission. In the opinion of management, the accompanying unaudited condensed consolidated financial statements reflect all adjustments consisting of normal recurring adjustments as necessary for a fair presentation of our financial position and results of operations.
The financial information as of December 31, 2019, has been derived from the audited financial statements contained in our Annual Report on Form 10-K for the year ended December 31, 2019 (“2019 Form 10-K”), but does not include all disclosures, including notes required by GAAP. As such, this quarterly report should be read in conjunction with the consolidated financial statements and related notes included in our 2019 Form 10-K. The Company follows the same accounting principles for preparing quarterly and annual reports.
Principles of Consolidation
The condensed consolidated balance sheets (“balance sheets”) include the accounts of the Company and its wholly owned subsidiaries, Bonanza Creek Energy Operating Company, LLC, Holmes Eastern Company, LLC, and Rocky Mountain Infrastructure, LLC. All significant intercompany accounts and transactions have been eliminated.
Use of Estimates
The preparation of the Company's condensed consolidated financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of oil and gas reserves, assets and liabilities, disclosure of contingent assets and liabilities at the date of the balance sheet, and the reported amounts of revenue and expenses during the reporting period. Actual results could differ from those estimates. The results of operations for the three months ended March 31, 2020, are not necessarily indicative of the results that may be expected for the year ending December 31, 2020. Further these estimates and other factors, including those outside of the Company's control, such as the impact of lower commodity prices, may impact the Company's business, financial condition, results of operations and cash flows.
Revenue Recognition
Sales of oil, natural gas, and natural gas liquids (“NGLs”) are recognized when performance obligations are satisfied at the point control of the product is transferred to the customer. The Company's contracts’ pricing provisions are tied to a market index, with certain adjustments based on, among other factors, whether a well delivers to a gathering or transmission line, quality of the oil or natural gas, and prevailing supply and demand conditions. As a result, the price of the oil, natural gas, and NGLs fluctuates to remain competitive with other available oil, natural gas, and NGLs supplies.
As further described in Note 6 - Commitments and Contingencies, one contract with NGL Crude Logistics, LLP (“NGL Crude”, known as the “NGL Crude agreement”) has an additional aspect of variable consideration related to the minimum volume commitments (“MVCs”) as specified in the agreement. On an on-going basis, the Company performs an analysis of expected risk adjusted production applicable to the NGL Crude agreement based on approved production plans to determine if liquidated damages to NGL Crude are probable. As of March 31, 2020, the Company believes that the volumes delivered to NGL Crude will be in excess of the MVCs required then and for the upcoming approved production plan. As a result of this analysis, to date, no variable consideration related to potential liquidated damages has been considered in the transaction price for the NGL Crude agreement.
Under the oil sales contracts, the Company sells oil production at the wellhead, or other contractually agreed-upon delivery points, and collects an agreed-upon index price, net of pricing differentials. In this scenario, the Company recognizes revenue when control transfers to the purchaser at the wellhead, or other contractually agreed-upon delivery point, at the net contracted price received.
5
Under the natural gas processing contracts, the Company delivers natural gas to an agreed-upon delivery point. The delivery points are specified within each contract, and the transfer of control varies between the inlet and outlet of the midstream processing facility. The midstream processing entity gathers and processes the natural gas and remits proceeds to the Company for the resulting sales of NGLs and residue gas. For the contracts where the Company maintains control through the outlet of the midstream processing facility, the Company recognizes revenue on a gross basis, with gathering, transportation, and processing fees presented as an expense in the Company's accompanying condensed consolidated statements of operations and comprehensive income (loss) (“statements of operations”). Alternatively, for those contracts where the Company relinquishes control at the inlet of the midstream processing facility, the Company recognizes natural gas and NGLs revenues based on the contracted amount of the proceeds received from the midstream processing entity and, as a result, the Company recognizes revenue on a net basis.
Under the product sales contracts, the Company invoices customers once the performance obligations have been satisfied, at which point payment is unconditional. Accordingly, the Company's product sales contracts do not give rise to contract assets or liabilities under this guidance. At March 31, 2020 and December 31, 2019, the Company's receivables from contracts with customers were $16.5 million and $43.7 million, respectively. Payment is generally received within 30 to 60 days after the date of production.
The Company records revenue in the month production is delivered to the purchaser. However, as stated above, settlement statements for certain natural gas and NGLs sales may not be received for 30 to 60 days after the date production is delivered, and as a result, the Company is required to estimate the amount of production delivered to the purchaser and the price that will be received for the sale of the product. The Company records the differences between its estimates and the actual amounts received for product sales in the month in which payment is received from the purchaser. For the period from January 1, 2020 through March 31, 2020, revenue recognized in the reporting period related to performance obligations satisfied in prior reporting periods was insignificant.
Revenue attributable to each identified revenue stream is disaggregated below (in thousands):
| Three Months Ended March 31, | |||||||||||
| 2020 | 2019 | ||||||||||
| Operating Revenues: | |||||||||||
| Crude oil sales | $ | 51,146 | $ | 60,790 | |||||||
| Natural gas sales | 6,018 | 7,456 | |||||||||
| Natural gas liquids sales | 3,241 | 4,348 | |||||||||
| Oil and gas sales | $ | 60,405 | $ | 72,594 | |||||||
Restricted Cash
The following table provides a reconciliation of cash, cash equivalents, and restricted cash reported within the balance sheets, which sum to the total of such amounts shown in the accompanying condensed consolidated statements of cash flows (“statements of cash flows”) (in thousands):
| As of March 31, | |||||||||||
| 2020 | 2019 | ||||||||||
| Cash and cash equivalents | $ | 11,052 | $ | 32,695 | |||||||
Restricted cash included in other noncurrent assets(1) | 95 | 87 | |||||||||
| Total cash, cash equivalents, and restricted cash as shown in the statements of cash flows | $ | 11,147 | $ | 32,782 | |||||||
__________________________
(1) Consists of funds for road maintenance and repairs.
6
Unproved Property
Unproved oil and gas property costs are evaluated for impairment when there is an indication that the carrying costs may not be fully recoverable. During the three months ended March 31, 2020, the Company incurred $30.1 million in abandonment and impairment of unproved properties due to the reassessment of estimated probable and possible reserve locations based primarily upon economic viability. During the three months ended March 31, 2019, the Company incurred $0.9 million in abandonment and impairment of unproved properties due to the expiration of non-core leases.
Accounting Pronouncements Recently Adopted and Issued
In June 2016, the FASB issued Update No. 2016-13, Financial Instruments - Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments. The update changes the impairment model for most financial assets and certain other instruments, including trade and other receivables, and requires entities to use a new forward-looking expected loss model that will result in the earlier recognition of allowances for losses. The amended standard was adopted using a modified retrospective approach on January 1, 2020. The Company considered past events (including historical experience), current economic and industry conditions, reasonable and supportable forecasts, and lives of receivable balances and loss experience. Historically and currently, the Company's credit losses on oil and natural gas sales receivables and joint interest receivables have not been significant, and the adoption of this standard did not have a material impact on its consolidated financial statements. As of March 31, 2020, the Company has an allowance of $0.8 million established against joint interest receivables.
In August 2018, the FASB issued Update No. 2018-13, Disclosure Framework - Changes to the Disclosure Requirements for Fair Value Measurement. The objective of this update is to improve the effectiveness of fair value measurement disclosures. The new standard was adopted on January 1, 2020. The standard only impacted the form of the Company's disclosures.
In March 2020, the FASB issued Update No. 2020-04, Reference Rate Reform, which provides temporary optional guidance to companies impacted by the transition away from the London Interbank Offered Rate (“LIBOR”). The amendment provides certain expedients and exceptions to applying GAAP in order to lessen the potential accounting burden when contracts, hedging relationships, and other transactions that reference LIBOR as a benchmark rate are modified. This amendment is effective upon issuance and expires on December 31, 2022. The Company is currently assessing the impact of the LIBOR transition and this update on the Company's financial statements.
There are no other accounting standards applicable to the Company that would have a material effect on the Company’s financial statements and disclosures that have been issued, but not yet adopted by the Company as of March 31, 2020, and through the filing date of this report.
7
NOTE 3 - LEASES
The Company’s right-of-use assets and lease liabilities are recognized at their discounted present value on the balance sheet, which include leases related to the asset classes reflected as of the dates indicated in the table below (in thousands):
| March 31, 2020 | December 31, 2019 | |||||||||||||
| Operating leases | ||||||||||||||
Field equipment(1) | $ | 36,688 | $ | 35,057 | ||||||||||
| Corporate leases | 2,193 | 2,462 | ||||||||||||
| Vehicles | 923 | 1,043 | ||||||||||||
| Total right-of-use asset | $ | 39,804 | $ | 38,562 | ||||||||||
Field equipment(1) | $ | 36,708 | $ | 35,075 | ||||||||||
| Corporate leases | 2,809 | 3,129 | ||||||||||||
| Vehicles | 903 | 1,026 | ||||||||||||
| Total lease liability | $ | 40,420 | $ | 39,230 | ||||||||||
| Finance leases | ||||||||||||||
Right-of-use asset - field equipment(1) | $ | 219 | $ | — | ||||||||||
Lease liability - field equipment(1) | 209 | — | ||||||||||||
__________________________
(1) Includes compressors, certain gas processing equipment, and other field equipment.
The lease amounts disclosed are presented on a gross basis. A portion of these costs may have been or will be billed to other working interest owners, and the Company's net share of these costs, once paid, are included in proved properties, other property and equipment, lease operating expenses, or general and administrative expenses, as applicable.
The Company recognizes operating lease expense on a straight-line basis. Finance lease expense is recognized based on the effective interest method for the lease liability and straight-line amortization for the right-of-use asset, resulting in more cost being recognized in earlier lease periods. Short-term and variable lease payments are recognized as incurred. Short-term lease cost represents payments for leases with a lease term of one year or less, excluding leases with a term of one month or less. Short-term leases include drilling rigs and other equipment. Drilling rig contracts are structured based on an allotted number of wells to be drilled consecutively at a daily operating rate. Short-term drilling rig costs include a non-lease labor component, which is treated as a single lease component.
8
The following table summarizes the components of the Company's gross lease costs incurred during the three months ended March 31, 2020 and 2019 (in thousands):
| Three Months Ended March 31, | ||||||||||||||
| 2020 | 2019 | |||||||||||||
Operating lease cost(1) | $ | 3,491 | $ | 2,350 | ||||||||||
| Finance lease cost: | ||||||||||||||
Amortization of right-of-use assets | 2 | — | ||||||||||||
| Interest on lease liabilities | 1 | — | ||||||||||||
| Short-term lease cost | 1,590 | 1,822 | ||||||||||||
Variable lease cost(2) | 91 | 20 | ||||||||||||
Sublease income(3) | (89) | (87) | ||||||||||||
| Total lease cost | $ | 5,086 | $ | 4,105 | ||||||||||
____________________________
(1) Includes office rent expense of $0.3 million for the three months ended March 31, 2020 and 2019.
(2) Variable lease cost represents differences between lease obligations and actual costs incurred for certain leases that do not have fixed payments related to both lease and non-lease components. Such incremental costs include lease payment increases or decreases driven by market price fluctuations and leased asset maintenance costs.
(3) The Company subleased a portion of its office space for the remainder of the office lease term.
The Company does not have any leases with an implicit interest rate that can be readily determined. As a result, the Company used the incremental borrowing rate, based on the Credit Facility benchmark rate, adjusted for facility utilization and lease term, to calculate the respective discount rates. Please refer to Note 5 - Long-term Debt for additional information.
The Company has certain lease agreements that provide for the option to extend, purchase, or terminate early, which was evaluated on each lease to arrive at the proper lease term. There were some leases for which the option to extend or purchase was factored into the resulting lease term. There were no leases where early termination was factored into the resulting lease term. The Company's weighted-average remaining lease terms and discount rates as of March 31, 2020 are as follows:
| Operating Leases | Finance Leases | |||||||||||||
| Weighted-average lease term (years) | 3.35 | 0.92 | ||||||||||||
| Weighted-average discount rate | 3.95% | 3.47% | ||||||||||||
Supplemental cash flow information related to leases for the three months ended March 31, 2020 and 2019 consisted of the following (in thousands):
| Three Months Ended March 31, | |||||||||||
| 2020 | 2019 | ||||||||||
| Cash paid for amounts included in the measurement of lease liabilities: | |||||||||||
| Operating cash flows from operating leases | $ | 3,133 | $ | 2,032 | |||||||
| Operating cash flows from finance leases | 1 | — | |||||||||
| Financing cash flows from finance leases | 10 | — | |||||||||
| Right-of-use assets obtained in exchange for new operating lease obligations | $ | 5,444 | $ | 1,197 | |||||||
| Right-of-use assets obtained in exchange for new finance lease obligations | 219 | — | |||||||||
9
Future commitments by year for the Company's operating and finance leases with a lease term of one year or more as of March 31, 2020 are presented in the table below. Such commitments are reflected at undiscounted values and are reconciled to the discounted present value recognized on the balance sheet as follows (in thousands):
| Operating Leases | Finance Leases | |||||||||||||
| Remainder of 2020 | $ | 10,862 | $ | 96 | ||||||||||
| 2021 | 13,116 | 118 | ||||||||||||
| 2022 | 10,719 | — | ||||||||||||
| 2023 | 6,378 | — | ||||||||||||
| 2024 | 2,017 | — | ||||||||||||
| Thereafter | 3 | — | ||||||||||||
| Total lease payments | 43,095 | 214 | ||||||||||||
| Less: imputed interest | (2,675) | (5) | ||||||||||||
| Total lease liability | $ | 40,420 | $ | 209 | ||||||||||
NOTE 4 - ACCOUNTS PAYABLE AND ACCRUED EXPENSES
Accounts payable and accrued expenses contain the following (in thousands):
| As of March 31, 2020 | As of December 31, 2019 | ||||||||||
| Accrued drilling and completion costs | $ | 16,780 | $ | 3,248 | |||||||
| Accounts payable trade | 14,608 | 17,117 | |||||||||
| Accrued general and administrative expense | 1,194 | 5,620 | |||||||||
| Accrued lease operating expense | 3,949 | 2,187 | |||||||||
| Accrued interest | 540 | 692 | |||||||||
| Accrued oil and gas hedging | — | 453 | |||||||||
| Accrued production and ad valorem taxes and other | 26,662 | 28,321 | |||||||||
| Total accounts payable and accrued expenses | $ | 63,733 | $ | 57,638 | |||||||
NOTE 5 - LONG-TERM DEBT
Credit Facility
On December 7, 2018, the Company entered into a reserve-based revolving facility, as the borrower, with JPMorgan Chase Bank, N.A., as the administrative agent, and a syndicate of financial institutions, as lenders (the “Credit Facility”). The Credit Facility has an aggregate original commitment amount of $750.0 million, an initial borrowing base of $350.0 million, and a maturity date of December 7, 2023. The Credit Facility borrowing base is redetermined on a semi-annual basis. The most recent redetermination was concluded on November 26, 2019, resulting in a reaffirmation of the borrowing base at $375.0 million; however, the Company chose to hold the aggregate elected commitments at $350.0 million. The next scheduled redetermination is set to occur in May 2020, but was not completed prior to the date of this filing.
Borrowings under the Credit Facility bear interest at a per annum rate equal to, at the option of the Company, either (i) LIBOR, subject to a 0% LIBOR floor plus a margin of 1.75% to 2.75%, based on the utilization of the Credit Facility (the “Eurodollar Rate”) or (ii) a fluctuating interest rate per annum equal to the greatest of (a) the rate of interest publicly announced by JPMorgan Chase Bank, N.A. as its prime rate, (b) the rate of interest published by the Federal Reserve Bank of New York as the federal funds effective rate, (c) the rate of interest published by the Federal Reserve Bank of New York as the overnight bank funding rate, or (d) a LIBOR offered rate for a one-month interest period, subject to a 0% LIBOR floor plus a margin of 0.75% to 1.75%, based on the utilization of the Credit Facility (the “Reference Rate”). Interest on borrowings that bear interest at the Eurodollar Rate shall be payable on the last day of the applicable interest period selected by the Company, which shall be one, two, three, or six months, and interest on borrowings that bear interest at the Reference Rate shall be payable quarterly in arrears. The Company's Credit Facility approximates fair value as the applicable interest rates are floating.
10
The Credit Facility is guaranteed by all wholly-owned subsidiaries of the Company (each, a “Guarantor” and, together with the Company, the “Credit Parties”), and is secured by first priority security interests on substantially all assets of each Credit Party, subject to customary exceptions.
The Credit Facility contains customary representations and affirmative covenants. The Credit Facility also contains customary negative covenants, which, among other things, and subject to certain exceptions, include restrictions on (i) liens, (ii) indebtedness, guarantees and other obligations, (iii) restrictions in agreements on liens and distributions, (iv) mergers or consolidations, (v) asset sales, (vi) restricted payments, (vii) investments, (viii) affiliate transactions, (ix) change of business, (x) foreign operations or subsidiaries, (xi) name changes, (xii) use of proceeds, letters of credit, (xiii) gas imbalances, (xiv) hedging transactions, (xv) additional subsidiaries, (xvi) changes in fiscal year or fiscal quarter, (xvii) operating leases, (xviii) prepayments of certain debt and other obligations, (xix) sales or discounts of receivables, and (xx) dividend payments. The Credit Parties are subject to certain financial covenants under the Credit Facility, as tested on the last day of each fiscal quarter, including, without limitation, (i) a maximum ratio of the Company’s consolidated indebtedness (subject to certain exclusions) to earnings before interest, income taxes, depreciation, depletion, and amortization, exploration expense, and other non-cash charges (“EBITDAX”) of 4.00 to 1.00 and (ii) a current ratio, as defined in the agreement, inclusive of the unused Commitments then available to be borrowed, to not be less than 1.00 to 1.00. The Company was in compliance with all covenants as of March 31, 2020, and through the filing date of this report.
For each of the periods ending March 31, 2020 and through the filing date of this report, the Company had $59.0 million outstanding on the Credit Facility and $80.0 million as of December 31, 2019.
In connection with the Credit Facility, the Company capitalized a total of $2.5 million in deferred financing costs. Of the total post-amortization net capitalized amounts, (i) $1.3 million and $1.4 million as of March 31, 2020 and December 31, 2019, respectively, are presented within other noncurrent assets and (ii) $0.5 million as of March 31, 2020 and December 31, 2019, is presented within the prepaid expenses and other line items in the accompanying condensed consolidated balance sheets (“balance sheets”).
For each of the three months ended March 31, 2020 and 2019, the Company incurred interest expense of $1.2 million. The Company capitalized $1.0 million of interest expense during the three months ended March 31, 2020. No interest was capitalized during the three months ended March 31, 2019.
NOTE 6 - COMMITMENTS AND CONTINGENCIES
Legal Proceedings
From time to time, the Company is involved in various commercial and regulatory claims, litigation, and other legal proceedings that arise in the ordinary course of its business. The Company assesses these claims in an effort to determine the degree of probability and range of possible loss for potential accrual in its condensed consolidated financial statements. In accordance with authoritative accounting guidance, an accrual is recorded for a loss contingency when its occurrence is probable and damages can be reasonably estimated based on the most likely anticipated outcome or the minimum amount within a range of possible outcomes. Because legal proceedings are inherently unpredictable and unfavorable resolutions could occur, assessing contingencies is highly subjective and requires judgments about uncertain future events. When evaluating contingencies, the Company may be unable to provide a meaningful estimate due to a number of factors, including the procedural status of the matter in question, the presence of complex or novel legal theories, and/or the ongoing discovery and development of information important to the matters. The Company regularly reviews contingencies to determine the adequacy of its accruals and related disclosures. No claims have been made, nor is the Company aware of any material uninsured liability which the Company may have, as it relates to any environmental cleanup, restoration, or the violation of any rules or regulations. As of the filing date of this report, there were no probable, material pending, or overtly threatened legal actions against the Company of which it was aware.
In February 2019, the Company was sent a notice of intent to sue (“NOI”) letter by WildEarth Guardians (“WEG”), an environmental non-governmental organization, alleging failure to obtain required permits under the federal Clean Air Act before constructing and operating well production facilities in the ozone non-attainment area around the Denver Metropolitan and North Front Range of Colorado, among other things. The Company is one of seven operators in the Wattenberg Field to receive such an NOI letter from WEG, and these letters appear to challenge long-established federal and state regulations and policies for permitting the construction and initial operation of upstream oil and gas production facilities in Colorado and elsewhere under the Clean Air Act and state counterpart statutes.
11
On May 3, 2019, WEG filed a lawsuit in the U.S. District Court for the District of Colorado against the Company and the other six operators who received the NOI, alleging claims consistent with those contained in the NOI letters. The allegations made in the lawsuit are based on novel and unprecedented interpretations of complex federal and state air quality laws and regulations. The Company has and will continue to vigorously defend against those allegations, and it will also coordinate as much as possible with state and federal permitting authorities to maintain the validity of its facilities’ current and future air permits. At this time, the Company is unable to estimate the lawsuit’s potential outcome.
Commitments
The Company is party to a purchase agreement to deliver fixed determinable quantities of crude oil to NGL Crude. The NGL Crude agreement includes defined volume commitments over a term ending in 2023. Under the terms of the NGL Crude agreement, the Company is required to make periodic deficiency payments for any shortfalls in delivering minimum gross volume commitments, which are set in -month periods. The minimum gross volume commitment will increase approximately 3% each year for the remainder of the contract, to a maximum of approximately 16,000 gross barrels per day. The aggregate financial commitment fee over the remaining term was $73.7 million as of March 31, 2020. Upon notifying NGL Crude at least twelve months prior to the expiration date of the NGL Crude agreement, the Company may elect to extend the term of the NGL Crude agreement for up to additional years.
The annual minimum commitment payments under the NGL Crude agreement for the next five years as of March 31, 2020 are presented below (in thousands):
NGL Crude Commitments(1) | |||||
| Remainder of 2020 | $ | 15,219 | |||
| 2021 | 23,316 | ||||
| 2022 | 24,009 | ||||
| 2023 | 11,200 | ||||
| 2024 | — | ||||
| 2025 and thereafter | — | ||||
| Total | $ | 73,744 | |||
____________________________
(1) The above calculation is based on the minimum volume commitment schedule (as defined in the NGL Crude agreement) and applicable differential fees.
Since the commencement of the NGL Crude agreement and through the remainder of the term of the agreement, the Company has not and does not expect to incur any deficiency payments.
There have been no other material changes from the commitments disclosed in the notes to the Company’s consolidated financial statements included in our 2019 Form 10-K. Refer to Note 3 - Leases, for lease commitments.
NOTE 7 - STOCK-BASED COMPENSATION
2017 Long Term Incentive Plan
Upon emergence from bankruptcy, the Company adopted a new Long Term Incentive Plan (the “2017 LTIP”), as established by the pre-emergence Board of Directors, which allows for the issuance of restricted stock units (“RSUs”), performance stock units (“PSUs”), and options, and reserved 2,467,430 shares of new common stock. See below for further discussion of awards granted under the 2017 LTIP.
The Company recorded compensation expense related to the awards granted under the 2017 LTIP as follows (in thousands):
| Three Months Ended March 31, | |||||||||||
| 2020 | 2019 | ||||||||||
| Restricted stock units | $ | 1,301 | $ | 1,085 | |||||||
| Performance stock units | (193) | 143 | |||||||||
| Stock options | 131 | 152 | |||||||||
| Total stock-based compensation | $ | 1,239 | $ | 1,380 | |||||||
12
As of March 31, 2020, unrecognized compensation expense will be amortized through the relevant periods as follows (in thousands):
| Unrecognized Compensation Expense | Final Year of Recognition | ||||||||||
| Restricted stock units | $ | 8,010 | 2023 | ||||||||
| Performance stock units | 955 | 2021 | |||||||||
| Stock options | 40 | 2020 | |||||||||
| $ | 9,005 | ||||||||||
Restricted Stock Units
The 2017 LTIP allows for the issuance of RSUs to members of the Board of Directors (the “Board”) and employees of the Company at the discretion of the Board. Each RSU represents one share of the Company's common stock to be released from restriction upon completion of the vesting period. The awards typically vest in one-third increments over three years. The RSUs are valued at the grant date share price and are recognized as general and administrative expense over the vesting period of the award.
No RSUs were granted during the three months ended March 31, 2020. A summary of the status and activity of non-vested restricted stock units for the three months ended March 31, 2020 is presented below:
| Restricted Stock Units | Weighted-Average Grant-Date Fair Value | ||||||||||
| Non-vested, beginning of year | 557,817 | $ | 26.95 | ||||||||
| Granted | — | — | |||||||||
| Vested | (13,674) | 19.70 | |||||||||
| Forfeited | (7,714) | 30.38 | |||||||||
| Non-vested, end of quarter | 536,429 | $ | 26.82 | ||||||||
Cash flows resulting from excess tax benefits are to be classified as part of cash flows from operating activities. Excess tax benefits are realized tax benefits from tax deductions for vested restricted stock in excess of the deferred tax asset attributable to stock compensation costs for such restricted stock. The Company recorded no excess tax benefits for the periods presented.
Performance Stock Units
The 2017 LTIP allows for the issuance of PSUs to employees at the sole discretion of the Board. The number of shares of the Company’s common stock that may be issued to settle PSUs ranges from zero to two times the number of PSUs awarded. The PSUs vest in their entirety at the end of the -year performance period. The total number of PSUs granted is evenly split between two performance criteria. The first criterion is based on a comparison of the Company’s absolute and relative total shareholder return (“TSR”) for the performance period compared with the TSRs of a group of peer companies for the same performance period. The TSR for the Company and each of the peer companies is determined by dividing (A) (i) the volume-weighted average share price for the last 30 trading days of the performance period minus (ii) the volume-weighted average share price for the 30 trading days preceding the beginning of the performance period, by (B) the volume-weighted average share price for the 30 trading days preceding the beginning of the performance period. The second criterion is based on the Company's average annual return on capital employed (“ROCE”) for each year during the -year performance period. Compensation expense associated with PSUs is recognized as general and administrative expense over the performance period. Because these awards depend on a combination of performance-based and market-based settlement criteria, compensation expense may be adjusted in future periods as the number of units expected to vest increases or decreases based on the Company’s expected ROCE performance. As of March 31, 2020, the Company does not expect any of the ROCE PSUs to vest and has accordingly adjusted the related compensation expense.
13
The fair value of the PSUs was measured at the grant date. The portion of the PSUs tied to the TSR required a stochastic process method using a Brownian Motion simulation. A stochastic process is a mathematically defined equation that can create a series of outcomes over time. These outcomes are not deterministic in nature, which means that by iterating the equations multiple times, different results will be obtained for those iterations. In the case of the Company’s TSRs, the Company could not predict with certainty the path its stock price or the stock prices of its peers would take over the performance period. By using a stochastic simulation, the Company created multiple prospective stock pathways, statistically analyzed these simulations, and ultimately made inferences regarding the most likely path the stock price would take. As such, because future stock prices are stochastic, or probabilistic with some direction in nature, the stochastic method, specifically the Brownian Motion Model, was deemed an appropriate method by which to determine the fair value of the portion of the PSUs tied to the TSR. Significant assumptions used in this simulation include the Company’s expected volatility, risk-free interest rate based on U.S. Treasury yield curve rates with maturities consistent with the performance period, as well as the volatilities for each of the Company’s peers.
No PSUs were granted during the three months ended March 31, 2020. A summary of the status and activity of performance stock units for the three months ended March 31, 2020 is presented below:
Performance Stock Units(1) | Weighted-Average Grant-Date Fair Value | ||||||||||
Non-vested, beginning of year | 153,470 | $ | 24.74 | ||||||||
Granted | — | — | |||||||||
Vested | — | — | |||||||||
Forfeited | — | — | |||||||||
| Non-vested, end of quarter | 153,470 | $ | 24.74 | ||||||||
___________________________
(1)The number of awards assumes that the associated performance condition is met at the target amount. The final number of shares of the Company’s common stock issued may vary depending on the performance multiplier, which ranges from zero to two, depending on the level of satisfaction of the performance condition.
Stock Options
The 2017 LTIP allows for the issuance of stock options to the Company's employees at the sole discretion of the Board. Options expire ten years from the grant date unless otherwise determined by the Board. Compensation expense on the stock options is recognized as general and administrative expense over the vesting period of the award.
Stock options are valued using a Black-Scholes Model where (i) expected volatility is based on an average historical volatility of a peer group selected by management over a period consistent with the expected life assumption on the grant date, (ii) the risk-free rate of return is based on the U.S. Treasury constant maturity yield on the grant date with a remaining term equal to the expected term of the awards, and (iii) the Company’s expected life of stock option awards is derived from the midpoint of the average vesting time and contractual term of the awards.
There were no stock options granted during the three months ended March 31, 2020. A summary of the status and activity of stock options for the three months ended March 31, 2020 is presented below:
| Stock Options | Weighted-Average Exercise Price | Weighted-Average Remaining Contractual Term (in years) | Aggregate Intrinsic Value (in thousands) | ||||||||||||||||||||
| Outstanding, beginning of year | 100,714 | $ | 34.36 | ||||||||||||||||||||
| Granted | — | — | |||||||||||||||||||||
| Exercised | — | — | |||||||||||||||||||||
| Forfeited | (5,976) | 34.36 | |||||||||||||||||||||
| Outstanding, end of quarter | 94,738 | $ | 34.36 | 6.9 | $ | — | |||||||||||||||||
| Number of options outstanding and exercisable | 64,632 | $ | 34.36 | 6.8 | $ | — | |||||||||||||||||
14
NOTE 8 - FAIR VALUE MEASUREMENTS
The Company follows fair value measurement authoritative guidance, which defines fair value, establishes a framework for using fair value to measure assets and liabilities, and expands disclosures about fair value measurements. The authoritative accounting guidance defines fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. The statement establishes a hierarchy for inputs used in measuring fair value that maximizes the use of observable inputs and minimizes the use of unobservable inputs by requiring that the most observable inputs be used when available. The hierarchy is broken down into three levels based on the reliability of the inputs as follows:
Level 1: Quoted prices are available in active markets for identical assets or liabilities
Level 2: Quoted prices in active markets for similar assets and liabilities, quoted prices for identical or similar instruments in markets that are not active, and model-derived valuations whose inputs are observable or whose significant value drivers are observable
Level 3: Significant inputs to the valuation model are unobservable
Financial and non-financial assets and liabilities are to be classified based on the lowest level of input that is significant to the fair value measurement. The Company’s assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of the fair value of assets and liabilities and their placement within the fair value hierarchy levels.
The following tables present the Company's financial and non-financial assets and liabilities that were accounted for at fair value on a recurring basis and their classification within the fair value hierarchy (in thousands):
| As of March 31, 2020 | |||||||||||||||||
| Level 1 | Level 2 | Level 3 | |||||||||||||||
Derivative assets | $ | — | $ | 90,551 | $ | — | |||||||||||
Derivative liabilities | $ | — | $ | 1,452 | $ | — | |||||||||||
| As of December 31, 2019 | |||||||||||||||||
| Level 1 | Level 2 | Level 3 | |||||||||||||||
Derivative assets | $ | — | $ | 3,005 | $ | — | |||||||||||
Derivative liabilities | $ | — | $ | 7,311 | $ | — | |||||||||||
Derivatives
Fair value of all derivative instruments are estimated with industry-standard models that consider various assumptions, including quoted forward prices for commodities, time value of money, volatility factors and current market and contractual prices for the underlying instruments, as well as other relevant economic measures. All valuations were compared against counterparty statements to verify the reasonableness of the estimate. The Company’s commodity swaps, collars, and puts were validated by observable transactions for the same or similar commodity options using the NYMEX futures index and were designated as Level 2 within the valuation hierarchy.
15
Proved Oil and Gas Properties
Proved oil and gas property costs are evaluated for impairment on a nonrecurring basis and reduced to fair value when there is an indication that the carrying costs exceed the sum of the undiscounted cash flows. Depending on the availability of data, the Company uses Level 3 inputs and either the income valuation technique, which converts future amounts to a single present value amount to measure the fair value of proved properties through an application of risk-adjusted discount rates and price forecasts selected by the Company’s management, or the market valuation approach. The calculation of the risk-adjusted discount rate is a significant management estimate based on the best information available. Management believes that the risk-adjusted discount rate is representative of current market conditions and reflects the following factors: estimates of future cash payments, expectations of possible variations in the amount and/or timing of cash flows, the risk premium, and nonperformance risk. The price forecast is based on the Company's internal budgeting model derived from the NYMEX strip pricing, adjusted for management estimates and basis differentials. Future operating costs are also adjusted as deemed appropriate for these estimates. Proved properties classified as held for sale are valued using a market approach, based on an estimated selling price, as evidenced by the most current bid prices received from third parties. If a relevant estimated selling price is not available, the Company utilizes the income valuation technique discussed above. There were no proved oil and gas property impairments during the three months ended March 31, 2020 and 2019.
NOTE 9 - ASSET RETIREMENT OBLIGATIONS
The Company recognizes an estimated liability for future costs to abandon its oil and gas properties. The fair value of the asset retirement obligation is recorded as a liability when incurred, which is typically at the time the asset is acquired or placed in service. There is a corresponding increase to the carrying value of the asset, which is included in the proved properties line item in the accompanying balance sheets. The Company depletes the amount added to proved properties and recognizes expense in connection with accretion of the discounted liability over the remaining estimated economic lives of the properties.
The Company’s estimated asset retirement obligation liability is based on historical experience in abandoning wells, estimated economic lives, estimated costs to abandon the wells, and regulatory requirements. The liability is discounted using the credit-adjusted risk-free rate estimated at the time the liability is incurred.
A roll-forward of the Company's asset retirement obligation is as follows (in thousands):
| Amount | |||||
Beginning balance as of December 31, 2019 | $ | 27,908 | |||
| Liabilities settled | (610) | ||||
| Additions | 64 | ||||
| Accretion expense | 260 | ||||
Ending balance as of March 31, 2020 | $ | 27,622 | |||
NOTE 10 - DERIVATIVES
The Company enters into commodity derivative contracts to mitigate a portion of its exposure to potentially adverse market changes in commodity prices and the associated impact on cash flows. All contracts are entered into for other-than-trading purposes. The Company’s derivatives include swaps, collars, and puts for oil and natural gas, and none of the derivative instruments qualify as having hedging relationships.
In a typical commodity swap agreement, if the agreed upon published third-party index price is lower than the swap strike price, the Company receives the difference between the index price and the agreed upon swap strike price. If the index price is higher than the swap strike price, the Company pays the difference.
A put gives the owner the right to sell the underlying commodity at a set price over the term of the contract. If the index settlement price is higher than the put fixed price, the put will expire worthless. If the settlement price is lower than the put fixed price, the Company will exercise the put and receive the difference between the settlement price and the put fixed price.
A cashless collar arrangement establishes a floor and ceiling price on future oil and gas production. When the settlement price is above the ceiling price, the Company pays the difference between the settlement price and the ceiling price. When the settlement price is below the floor price, the Company receives the difference between the settlement price and floor price. In the event that the settlement price is between the ceiling and the floor, no payment or receipt occurs.
16
A basis swap arrangement guarantees a price differential from a specified delivery point to an agreed upon reference point. The Company receives the difference between the price differential and the stated terms, if the price differential is greater than the stated terms. The Company pays the difference between the price differential and the stated terms, if the stated terms are greater than the price differential.
As of March 31, 2020, the Company had entered into the following commodity derivative contracts:
| Crude Oil (NYMEX WTI) | Natural Gas (NYMEX Henry Hub) | Natural Gas (CIG Basis) | ||||||||||||||||||||||||||||||||||||
| Bbls/day | Weighted Avg. Price per Bbl | MMBtu/day | Weighted Avg. Price per MMBtu | MMBtu/day | Weighted Avg. Basis Differential to CIG Price per MMBtu | |||||||||||||||||||||||||||||||||
| 2Q20 | ||||||||||||||||||||||||||||||||||||||
| Cashless Collar | 7,500 | $54.00/$61.01 | — | — | — | — | ||||||||||||||||||||||||||||||||
| Swap | 1,500 | $54.98 | 10,000 | $2.61 | 30,000 | $0.54 | ||||||||||||||||||||||||||||||||
| Put | 4,000 | $32.50 | — | — | — | — | ||||||||||||||||||||||||||||||||
| 3Q20 | ||||||||||||||||||||||||||||||||||||||
| Cashless Collar | 6,000 | $52.67/$58.40 | — | — | — | — | ||||||||||||||||||||||||||||||||
| Swap | 3,500 | $54.12 | — | — | 30,000 | $0.54 | ||||||||||||||||||||||||||||||||
| Put | 4,000 | $32.50 | — | — | — | — | ||||||||||||||||||||||||||||||||
| 4Q20 | ||||||||||||||||||||||||||||||||||||||
| Cashless Collar | 6,000 | $52.67/$58.40 | — | — | — | — | ||||||||||||||||||||||||||||||||
| Swap | 3,500 | $54.12 | — | — | 30,000 | $0.54 | ||||||||||||||||||||||||||||||||
| Put | 3,000 | $32.50 | ||||||||||||||||||||||||||||||||||||
| 1Q21 | ||||||||||||||||||||||||||||||||||||||
| Cashless Collar | 2,000 | $50.50/$55.19 | 20,000 | $2.25/$2.52 | — | — | ||||||||||||||||||||||||||||||||
| Swap | 5,000 | $54.48 | — | — | — | — | ||||||||||||||||||||||||||||||||
| 2Q21 | ||||||||||||||||||||||||||||||||||||||
| Cashless Collar | 500 | $52.00/$55.00 | 20,000 | $2.25/$2.52 | — | — | ||||||||||||||||||||||||||||||||
| Swap | 4,000 | $54.13 | — | — | — | — | ||||||||||||||||||||||||||||||||
| 3Q21 | ||||||||||||||||||||||||||||||||||||||
| Cashless Collar | — | — | 20,000 | $2.25/$2.52 | — | — | ||||||||||||||||||||||||||||||||
| Swap | 2,500 | $54.45 | — | — | — | — | ||||||||||||||||||||||||||||||||
| 4Q21 | ||||||||||||||||||||||||||||||||||||||
| Cashless Collar | — | — | 20,000 | $2.25/$2.52 | — | — | ||||||||||||||||||||||||||||||||
| Swap | 1,000 | $55.20 | — | — | — | — | ||||||||||||||||||||||||||||||||
17
As of the filing date of this report, the Company had entered into the following commodity derivative contracts:
| Crude Oil (NYMEX WTI) | Natural Gas (NYMEX Henry Hub) | Natural Gas (CIG Basis) | ||||||||||||||||||||||||||||||||||||
| Bbls/day | Weighted Avg. Price per Bbl | MMBtu/day | Weighted Avg. Price per MMBtu | MMBtu/day | Weighted Avg. Basis Differential to CIG Price per MMBtu | |||||||||||||||||||||||||||||||||
| 2Q20 | ||||||||||||||||||||||||||||||||||||||
| Cashless Collar | 7,500 | $54.00/$61.01 | — | — | — | — | ||||||||||||||||||||||||||||||||
| Swap | 2,500 | $44.48 | 10,000 | $2.61 | 30,000 | $0.54 | ||||||||||||||||||||||||||||||||
| Put | 4,000 | $32.50 | — | — | — | — | ||||||||||||||||||||||||||||||||
| 3Q20 | ||||||||||||||||||||||||||||||||||||||
| Cashless Collar | 6,000 | $52.67/$58.40 | 10,000 | $2.25/$2.67 | — | — | ||||||||||||||||||||||||||||||||
| Swap | 3,500 | $54.12 | — | — | 30,000 | $0.54 | ||||||||||||||||||||||||||||||||
| Put | 4,000 | $32.50 | — | — | — | — | ||||||||||||||||||||||||||||||||
| 4Q20 | ||||||||||||||||||||||||||||||||||||||
| Cashless Collar | 6,000 | $52.67/$58.40 | 10,000 | $2.25/$2.67 | — | — | ||||||||||||||||||||||||||||||||
| Swap | 3,500 | $54.12 | 10,000 | $2.30 | 30,000 | $0.54 | ||||||||||||||||||||||||||||||||
| Put | 3,000 | $32.50 | — | — | — | — | ||||||||||||||||||||||||||||||||
| 1Q21 | ||||||||||||||||||||||||||||||||||||||
| Cashless Collar | 2,000 | $50.50/$55.19 | 30,000 | $2.25/$2.57 | — | — | ||||||||||||||||||||||||||||||||
| Swap | 5,000 | $54.48 | — | — | 20,000 | $0.43 | ||||||||||||||||||||||||||||||||
| 2Q21 | ||||||||||||||||||||||||||||||||||||||
| Cashless Collar | 1,000 | $41.00/$49.18 | 20,000 | $2.25/$2.52 | — | — | ||||||||||||||||||||||||||||||||
| Swap | 4,000 | $54.13 | — | — | 20,000 | $0.43 | ||||||||||||||||||||||||||||||||
| 3Q21 | ||||||||||||||||||||||||||||||||||||||
| Cashless Collar | 500 | $30.00/$43.35 | 20,000 | $2.25/$2.52 | — | — | ||||||||||||||||||||||||||||||||
| Swap | 2,500 | $54.45 | — | — | 20,000 | $0.43 | ||||||||||||||||||||||||||||||||
| 4Q21 | ||||||||||||||||||||||||||||||||||||||
| Cashless Collar | 1,000 | $30.00/$43.80 | 20,000 | $2.25/$2.52 | — | — | ||||||||||||||||||||||||||||||||
| Swap | 1,000 | $55.20 | — | — | 20,000 | $0.43 | ||||||||||||||||||||||||||||||||
| 1Q22 | ||||||||||||||||||||||||||||||||||||||
| Cashless Collar | 1,000 | $30.00/$43.80 | — | — | — | — | ||||||||||||||||||||||||||||||||
18
Derivative Assets and Liabilities Fair Value
The Company’s commodity derivatives are measured at fair value and are included in the accompanying balance sheets as derivative assets and liabilities. The following table contains a summary of all the Company’s derivative positions reported on the accompanying balance sheets for the periods below (in thousands):
| As of March 31, 2020 | As of December 31, 2019 | |||||||||||||
| Derivative Assets: | ||||||||||||||
| Commodity contracts - current | $ | 77,973 | $ | 2,884 | ||||||||||
| Commodity contracts - noncurrent | 12,578 | 121 | ||||||||||||
| Derivative Liabilities: | ||||||||||||||
| Commodity contracts - current | (1,248) | (6,390) | ||||||||||||
| Commodity contracts - noncurrent | (204) | (921) | ||||||||||||
| Total derivative assets (liabilities), net | $ | 89,099 | $ | (4,306) | ||||||||||
The following table summarizes the components of the derivative gain (loss) presented on the accompanying statements of operations for the periods below (in thousands):
| Three Months Ended March 31, | |||||||||||
| 2020 | 2019 | ||||||||||
| Derivative cash settlement gain (loss): | |||||||||||
| Oil contracts | $ | 10,438 | $ | 2,078 | |||||||
| Gas contracts | 816 | (1,142) | |||||||||
Total derivative cash settlement gain(1) | 11,254 | 936 | |||||||||
| Change in fair value gain (loss) | 89,165 | (37,480) | |||||||||
Total derivative gain (loss)(1) | $ | 100,419 | $ | (36,544) | |||||||
_______________________________
(1)Total derivative gain (loss) and total derivative cash settlement gain for the three months ended March 31, 2020 and 2019 are reported in the derivative (gain) loss line item and derivative cash settlements line item in the accompanying statements of cash flows, within the cash flows from operating activities.
NOTE 11 - EARNINGS PER SHARE
The Company issues RSUs, which represent the right to receive, upon vesting, one share of the Company's common stock. The number of potentially dilutive shares related to RSUs is based on the number of shares, if any, that would be issuable at the end of the respective reporting period, assuming that date was the end of the vesting period. The Company issues PSUs, which represent the right to receive, upon settlement of the PSUs, a number of shares of the Company's common stock that ranges from zero to two times the number of PSUs granted on the award date. The number of potentially dilutive shares related to PSUs is based on the number of shares, if any, that would be issuable at the end of the respective reporting period, assuming that date was the end of the performance period applicable to such PSUs. The Company issued stock options and warrants, which both represent the right to purchase the Company's common stock at a specified price. The number of potentially dilutive shares related to the stock options is based on the number of shares, if any, that would be exercised at the end of the respective reporting period, assuming that date was the end of such stock options' term. The number of potentially dilutive shares related to the warrants is based on the number of shares, if any, that would be exercisable at the end of the respective reporting period.
Please refer to Note 7 - Stock-Based Compensation for additional discussion.
19
The Company uses the treasury stock method to calculate earnings per share as shown in the following table (in thousands, except per share amounts):
| Three Months Ended March 31, | |||||||||||
| 2020 | 2019 | ||||||||||
| Net income (loss) | $ | 78,551 | $ | (6,993) | |||||||
| Basic net income (loss) per common share | $ | 3.80 | $ | (0.34) | |||||||
| Diluted net income (loss) per common share | $ | 3.80 | $ | (0.34) | |||||||
| Weighted-average shares outstanding - basic | 20,649 | 20,557 | |||||||||
| Add: dilutive effect of contingent stock awards | 35 | — | |||||||||
| Weighted-average shares outstanding - diluted | 20,684 | 20,557 | |||||||||
There were 648,476 and 173,252 shares that were anti-dilutive for the three months ended March 31, 2020 and 2019, respectively. The Company was in a net loss position for the three months ended March 31, 2019, which made all potentially dilutive shares anti-dilutive.
The exercise price of the Company's warrants was in excess of the Company's stock price; therefore, they were excluded from the earnings per share calculation.
NOTE 12 - INCOME TAXES
Deferred tax assets and liabilities are measured by applying the provisions of enacted tax laws to determine the amount of taxes payable or refundable currently or in future years related to cumulative temporary differences between the tax basis of assets and liabilities and amounts reported in the Company's balance sheets. The tax effect of the net change in the cumulative temporary differences during each period in the deferred tax assets and liabilities determines the periodic provision for deferred taxes.
The Company assesses the recoverability of its deferred tax assets each period by considering whether it is more likely than not that all or a portion of the deferred tax assets will be realized. In making such determination, the Company considers all available positive and negative evidence, including future reversals of temporary differences, tax-planning strategies, projected future taxable income, and results of operations. As a result of the Company's analysis, it was concluded that as of March 31, 2020 and December 31, 2019, a full valuation allowance should be established against the Company's deferred tax asset. The Company will continue to monitor facts and circumstances in the reassessment of the likelihood that the deferred tax assets will be realized.
Federal income tax expense differs from the amount that would be provided by applying the statutory United States federal income tax rate of 21% to income before income taxes primarily due to the effect of state income taxes, changes in valuation allowances, and other permanent differences.
As of March 31, 2020 and December 31, 2019, the Company had no unrecognized tax benefits. The Company's management does not believe that there are any new items or changes in facts or judgments that would impact the Company's tax position taken thus far in 2020.
20
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations.
The following discussion and analysis of our financial condition and results of operations should be read in conjunction with “Management’s Discussion and Analysis of Financial Condition and Results of Operations” contained in our Annual Report on Form 10-K for the year ended December 31, 2019, as well as the unaudited condensed consolidated financial statements and notes thereto included in this Quarterly Report on Form 10-Q.
Executive Summary
We are an independent Denver-based exploration and production company focused on the acquisition, development, and extraction of oil and associated liquids-rich natural gas in the United States. Our oil and liquids-weighted assets and operations are concentrated in the rural portions of the Wattenberg Field in Colorado. Our development and extraction activities are primarily directed at the horizontal development of the Niobrara and Codell formations in the Denver-Julesburg (“DJ”) Basin. The majority of our revenues are generated through the sale of oil, natural gas, and natural gas liquids production.
The Company’s primary objective is to maximize shareholder returns by responsibly developing our oil and gas resources. We seek to balance production growth with maintaining a conservative balance sheet. Key aspects of our strategy include multi-well pad development across our leasehold, enhanced completions through continuous design evaluation, utilization of scaled infrastructure, continuous safety improvement, strict adherence to health and safety regulations, and environmental stewardship.
Financial and Operating Results
Our financial and operational results include:
•General and administrative expense per Boe decreased by 24% during the three months ended March 31, 2020 when compared to the same period in 2019 and is expected to further decrease throughout 2020;
•Lease operating expense per Boe decreased by 13% for the three months ended March 31, 2020 when compared to the same period in 2019 and is expected to further decrease throughout 2020;
•Crude oil equivalent sales volumes increased 21% for the three months ended March 31, 2020 when compared to the same period in 2019 despite the significant curtailment of our drilling and completion program in response to the drop in commodity prices;
•Borrowings under our Credit Facility were reduced by $21.0 million to $59.0 million during the three months ended March 31, 2020 from the $80.0 million outstanding at December 31, 2019;
•Total liquidity of $302.1 million at March 31, 2020, consisting of cash on hand plus funds available under our Credit Facility. Please refer to Liquidity and Capital Resources below for additional discussion;
•Cash flows provided by operating activities for the three months ended March 31, 2020 were $48.0 million, as compared to cash flows provided by operating activities of $41.7 million during the three months ended March 31, 2019. Please refer to Liquidity and Capital Resources below for additional discussion; and
•Incurred capital expenditures, inclusive of accruals, of $41.1 million during the three months ended March 31, 2020.
Rocky Mountain Infrastructure
The Company's gathering, treating, and production facilities, maintained under its Rocky Mountain Infrastructure, LLC (“RMI”) subsidiary, provide many operational benefits to the Company and provide cost economies of a centralized system. The RMI facilities reduce gathering system pressures at the wellhead, thereby improving hydrocarbon recovery. Additionally, with eleven interconnects to four different natural gas processors, RMI helps ensure that the Company's production is not constrained by any single midstream service provider. Furthermore, in 2019, the Company installed a new oil gathering line to Riverside Terminal, which resulted in a corresponding $1.50 per barrel reduction to our oil differentials for barrels transported on such gathering line. Finally, the system reduces facility site footprints, leading to more cost-efficient operations and reduced surface disturbance. The net book value of the Company's RMI assets was $152.8 million as of March 31, 2020.
21
Outlook for 2020
The recent worldwide outbreak of COVID-19, the uncertainty regarding the impact of COVID-19, and various governmental actions taken to mitigate the impact of COVID-19, have resulted in an unprecedented decline in demand for oil and natural gas. At the same time, the decision by Saudi Arabia in March 2020 to drastically reduce export prices and increase oil production further increased the excess supply of oil and natural gas. Due to the decline in crude oil prices and ongoing uncertainty regarding the oil supply-demand macro environment as a result of these events, we have recently suspended all drilling and significantly reduced completion and infrastructure activities.
The COVID-19 outbreak and its development into a pandemic in March 2020 have also required that we take precautionary measures intended to help minimize the risk to our business, employees, customers, suppliers, and the communities in which we operate. Our operational employees are currently still able to work on site. However, we have taken various precautionary measures with respect to our operational employees such as requiring them to verify they have not experienced any symptoms consistent with COVID-19, or been in close contact with someone showing such symptoms, before reporting to the work site, quarantining any operational employees who have shown signs of COVID-19 (regardless of whether such employee has been confirmed to be infected), and imposing social distancing requirements on work sites, all in accordance with the guidelines released by the Center for Disease Control. In addition, most of our non-operational employees are now working remotely. We have not yet experienced any material operational disruptions (including disruptions from our suppliers and service providers) as a result of the COVID-19 outbreak, nor had any confirmed cases of COVID-19 on any of our work sites.
The Company's initial 2020 capital budget of $215.0 million to $235.0 million assumed the continuation of a one-rig operated program in the Company’s legacy acreage and the startup of a one-rig non-operated program in the Company’s French Lake area in late 2020. However, due to the unprecedented drop in commodity prices that commenced in early March 2020, the Company updated its 2020 operating plan to reflect an anticipated 2020 capital budget of $80.0 million to $100.0 million. The Company’s reduced planned development activity included limited drilling and completion activity that concluded in March 2020. We now estimate our capital budget will be between $60.0 million and $70.0 million as our non-operated capital estimate has been reduced and we continue to receive cost concessions from capital service providers.
Should commodity prices recover, and the economic returns justify resuming limited development activity, we will do so. Actual capital expenditures could vary significantly based on, among other things, changes in the operator’s development pace in French Lake, market conditions, commodity prices, drilling and completion costs, well results, and changes in the borrowing base under our Credit Facility.
In further response to the recent drop in commodity prices, both our named executive officers and our independent directors have voluntarily reduced their compensation. Effective in early April 2020, our Chief Executive Officer’s salary was reduced by 12.5%, the other named executive officers’ salaries were each reduced by 10%, and our independent directors’ base annual cash retainers were reduced by 15%. In addition, the Company completed a 12% reduction in its workforce during the first quarter, which helped allow the Company to lower its 2020 recurring cash G&A guidance to a range of $27 million to $29 million, down 13% from $32 million in 2019. The Company has also identified, and is implementing, approximately $8 million in LOE and RMI operating expense savings compared to the Company’s original 2020 plan.
22
Results of Operations
The following table summarizes our product revenues, sales volumes, and average sales prices for the periods indicated:
| Three Months Ended March 31, | |||||||||||||||||||||||
| 2020 | 2019 | Change | Percent Change | ||||||||||||||||||||
| Revenues (in thousands): | |||||||||||||||||||||||
Crude oil sales(1) | $ | 50,589 | $ | 60,211 | $ | (9,622) | (16) | % | |||||||||||||||
Natural gas sales(2) | 4,962 | 6,772 | (1,810) | (27) | % | ||||||||||||||||||
Natural gas liquids sales | 3,241 | 4,348 | (1,107) | (25) | % | ||||||||||||||||||
| Product revenue | $ | 58,792 | $ | 71,331 | $ | (12,539) | (18) | % | |||||||||||||||
| Sales Volumes: | |||||||||||||||||||||||
Crude oil (MBbls) | 1,229.4 | 1,208.2 | 21.2 | 2 | % | ||||||||||||||||||
Natural gas (MMcf) | 3,562.7 | 2,198.4 | 1,364.3 | 62 | % | ||||||||||||||||||
Natural gas liquids (MBbls) | 436.9 | 291.6 | 145.3 | 50 | % | ||||||||||||||||||
Crude oil equivalent (MBoe)(3) | 2,260.1 | 1,866.2 | 393.9 | 21 | % | ||||||||||||||||||
Average Sales Prices (before derivatives)(4): | |||||||||||||||||||||||
| Crude oil (per Bbl) | $ | 41.15 | $ | 49.83 | $ | (8.68) | (17) | % | |||||||||||||||
| Natural gas (per Mcf) | $ | 1.39 | $ | 3.08 | $ | (1.69) | (55) | % | |||||||||||||||
| Natural gas liquids (per Bbl) | $ | 7.42 | $ | 14.91 | $ | (7.49) | (50) | % | |||||||||||||||
Crude oil equivalent (per Boe)(3) | $ | 26.01 | $ | 38.22 | $ | (12.21) | (32) | % | |||||||||||||||
Average Sales Prices (after derivatives)(4): | |||||||||||||||||||||||
| Crude oil (per Bbl) | $ | 49.64 | $ | 51.55 | $ | (1.91) | (4) | % | |||||||||||||||
| Natural gas (per Mcf) | $ | 1.62 | $ | 2.56 | $ | (0.94) | (37) | % | |||||||||||||||
| Natural gas liquids (per Bbl) | $ | 7.42 | $ | 14.91 | $ | (7.49) | (50) | % | |||||||||||||||
Crude oil equivalent (per Boe)(3) | $ | 30.99 | $ | 38.72 | $ | (7.73) | (20) | % | |||||||||||||||
_____________________________
(1)Crude oil sales excludes $0.6 million of oil transportation revenues from third parties, which do not have associated sales volumes, for each of the three months ended March 31, 2020 and 2019.
(2)Natural gas sales excludes $1.0 million and $0.7 million of gas gathering revenues from third parties, which do not have associated sales volumes, for the three months ended March 31, 2020 and 2019, respectively.
(3)Determined using the ratio of 6 Mcf of natural gas to 1 Bbl of crude oil.
(4)Derivatives economically hedge the price we receive for crude oil and natural gas. For the three months ended March 31, 2020, the derivative cash settlement gain for oil contracts was approximately $10.4 million, and the derivative cash settlement gain for natural gas contracts was approximately $0.8 million. For the three months ended March 31, 2019, the derivative cash settlement gain for oil contracts was $2.1 million, and the derivative cash settlement loss for gas contracts was $1.1 million. Please refer to Note 10 - Derivatives of Part I, Item 1 of this report for additional disclosures.
Product revenues decreased by 18% to $58.8 million for the three months ended March 31, 2020 compared to $71.3 million for the three months ended March 31, 2019. The primary driver of the decrease in revenue is the $12.21 or 32% decrease in oil equivalent pricing offset by a 21% increase in sales volumes. The increase in sales volumes is due to turning 38 gross wells to sales during the twelve-month period ending March 31, 2020.
23
The following table summarizes our operating expenses for the periods indicated:
| Three Months Ended March 31, | |||||||||||||||||||||||
| 2020 | 2019 | Change | Percent Change | ||||||||||||||||||||
| Expenses (in thousands): | |||||||||||||||||||||||
| Lease operating expense | $ | 5,699 | $ | 5,426 | $ | 273 | 5 | % | |||||||||||||||
| Midstream operating expense | 4,014 | 2,321 | 1,693 | 73 | % | ||||||||||||||||||
| Gathering, transportation, and processing | 3,481 | 4,022 | (541) | (13) | % | ||||||||||||||||||
| Severance and ad valorem taxes | 5,173 | 4,248 | 925 | 22 | % | ||||||||||||||||||
| Exploration | 373 | 97 | 276 | 285 | % | ||||||||||||||||||
| Depreciation, depletion, and amortization | 21,584 | 15,759 | 5,825 | 37 | % | ||||||||||||||||||
| Abandonment and impairment of unproved properties | 30,057 | 879 | 29,178 | 3,319 | % | ||||||||||||||||||
| Bad debt expense | 576 | — | 576 | 100 | % | ||||||||||||||||||
| General and administrative expense | 9,429 | 10,278 | (849) | (8) | % | ||||||||||||||||||
| Operating Expenses | $ | 80,386 | $ | 43,030 | $ | 37,356 | 87 | % | |||||||||||||||
| Selected Costs ($ per Boe): | |||||||||||||||||||||||
| Lease operating expense | $ | 2.52 | $ | 2.91 | $ | (0.39) | (13) | % | |||||||||||||||
| Midstream operating expense | 1.78 | 1.24 | 0.54 | 44 | % | ||||||||||||||||||
| Gathering, transportation, and processing | 1.54 | 2.16 | (0.62) | (29) | % | ||||||||||||||||||
| Severance and ad valorem taxes | 2.29 | 2.28 | 0.01 | — | % | ||||||||||||||||||
| Exploration | 0.17 | 0.05 | 0.12 | 240 | % | ||||||||||||||||||
| Depreciation, depletion, and amortization | 9.55 | 8.44 | 1.11 | 13 | % | ||||||||||||||||||
| Abandonment and impairment of unproved properties | 13.30 | 0.47 | 12.83 | 2,730 | % | ||||||||||||||||||
| Bad debt expense | 0.25 | — | 0.25 | 100 | % | ||||||||||||||||||
| General and administrative expense | 4.17 | 5.51 | (1.34) | (24) | % | ||||||||||||||||||
| Operating Expenses | $ | 35.57 | $ | 23.06 | $ | 12.51 | 54 | % | |||||||||||||||
Lease operating expense. Our lease operating expense increased $0.3 million, or 5%, to $5.7 million for the three months ended March 31, 2020, from $5.4 million for the three months ended March 31, 2019, and decreased on an equivalent basis per Boe by 13%. The overall increase was primarily due to higher salt water disposal costs, and the lease operating expense per unit decreased due to oil equivalent sales volumes being 21% higher in the later period.
Midstream operating expense. Our midstream operating expense increased $1.7 million to $4.0 million for the three months ended March 31, 2020, from $2.3 million for the three months ended March 31, 2019, and increased 44% on a per Boe basis during the comparable periods. The increase was primarily due to costs associated with the Company's new and expanded oil gathering line connected to the Riverside Terminal that came online in July 2019.
Gathering, transportation, and processing. Gathering, transportation, and processing expense decreased by $0.5 million to $3.5 million for the three months ended March 31, 2020, from $4.0 million for the three months ended March 31, 2019. Sales volumes have a direct correlation to gathering, transportation, and processing expense. Although sales volumes increased 21% during the three months ended March 31, 2020 as compared to the three months ended March 31, 2019, a decrease in fees on sales contracts contributed to the overall decrease in gathering, transportation, and processing expense.
Severance and ad valorem taxes. Our severance and ad valorem taxes increased 22% to $5.2 million for the three months ended March 31, 2020, from $4.2 million for the three months ended March 31, 2019. The increase was primarily due to additional property value associated with ad valorem taxes between the comparable periods.
Depreciation, depletion, and amortization. Our depreciation, depletion, and amortization expense increased 37% to $21.6 million for the three months ended March 31, 2020, from $15.8 million for the three months ended March 31, 2019, and increased 13% on a per Boe basis during the comparable periods. The increase in depreciation, depletion, and amortization expense during the three months ended March 31, 2020 when compared to the three months ended March 31, 2019 is the result of (i) a $201.3 million increase in the depletable property base and (ii) an increase in the depletion rate driven by a substantial increase in production between the comparable periods.
24
Abandonment and impairment of unproved properties. During the three months ended March 31, 2020, the Company incurred a $30.1 million abandonment and impairment of unproved properties due to the reassessment of estimated probable and possible reserve locations based primarily upon economic viability. In addition, during the three months ended March 31, 2019, the Company incurred $0.9 million in abandonment and impairment of unproved properties costs due to the expiration of non-core leases.
Bad debt expense. Our bad debt expense increased 100% to $0.6 million for the three months ended March 31, 2020, compared to the three months ended March 31, 2019. The increase is due to the establishment of an allowance against our joint interest receivable, which have greater recoverability risk due to the deterioration of commodity prices.
General and administrative. Our general and administrative expense decreased by $0.8 million or 8% for the three months ended March 31, 2020, compared to the three months ended March 31, 2019, and decreased by 24% on a per Boe basis between the comparable periods. The decrease in general and administrative expense between the comparable periods is primarily due to a decrease in salaries, benefits, and stock compensation expense. General and administrative expense per Boe decreased on a higher percentage basis due to oil equivalent sales volumes being 21% higher during the three months ended March 31, 2020 as compared to the same period in 2019.
Derivative gain (loss). Our derivative gain for the three months ended March 31, 2020 was $100.4 million, as compared to a derivative loss of $36.5 million for the three months ended March 31, 2019. Our derivative gain is due to settlements and fair market value adjustments caused by market prices being lower than our contracted hedge prices. Please refer to Note 10 - Derivatives of Part I, Item 1 of this report for additional discussion.
Interest expense. Our interest expense for the three months ended March 31, 2020 and 2019 was $0.2 million and $1.2 million, respectively. Average debt outstanding for the three months ended March 31, 2020 and 2019 was $84.8 million and $64.7 million, respectively. The components of interest expense for the periods presented are as follows (in thousands):
| Three Months Ended March 31, | |||||||||||
| 2020 | 2019 | ||||||||||
| Credit Facility | $ | 810 | $ | 758 | |||||||
| Commitment fees on available borrowing base under the Credit Facility | 251 | 268 | |||||||||
| Amortization of deferred financing costs | 123 | 125 | |||||||||
| Capitalized interest | (967) | — | |||||||||
| Total interest expense, net | $ | 217 | $ | 1,151 | |||||||
Liquidity and Capital Resources
The Company's anticipated sources of liquidity include cash from operating activities, borrowings under the Credit Facility, proceeds from sales of assets, and potential proceeds from capital and/or debt markets. Our cash flows from operating activities are subject to significant volatility due to changes in commodity prices, as well as variations in our production. The prices for these commodities are driven by a number of factors beyond our control, including global and regional product supply and demand, weather, product distribution, refining and processing capacity, regulatory constraints, and other supply chain dynamics, among other factors. To mitigate pricing risk, we have approximately 100% of our average 2020 guided oil production hedged as of March 31, 2020 and as of the filing date of this report. Consequently, the value of our commodity contracts as of March 31, 2020 was a net asset of $89.1 million. Additionally, in light of the recent suspension of drilling activities, we intend to pay down our Credit Facility to an undrawn balance by December 31, 2020 using net cash provided by operating activities.
As of March 31, 2020, our liquidity was $302.1 million, consisting of $11.1 million of cash on hand and $291.0 million of available borrowing capacity on the Credit Facility. The next scheduled redetermination is set to occur in May 2020, but was not completed prior to the date of this filing. The Company does not expect that any reduction resulting from the May 2020 redetermination will result in a substantial impact to our future operations or liquidity.
We anticipate investing approximately $60.0 million to $70.0 million during 2020, which will allow us to preserve our reserve value while maintaining almost flat production.
Our weighted-average interest rate on borrowings from the Credit Facility was 3.78% for the three months ended March 31, 2020. As of both March 31, 2020 and the date of this filing, we had $59.0 million outstanding on our Credit Facility.
25
The following table summarizes our cash flows and other financial measures for the periods indicated (in thousands):
| Three Months Ended March 31, | |||||||||||
| 2020 | 2019 | ||||||||||
| Net cash provided by operating activities | $ | 47,994 | $ | 41,721 | |||||||
| Net cash used in investing activities | (26,871) | (36,788) | |||||||||
| Net cash provided by (used in) financing activities | (21,071) | 14,847 | |||||||||
| Cash, cash equivalents, and restricted cash | 11,147 | 32,782 | |||||||||
| Acquisition of oil and gas properties | (284) | (1,362) | |||||||||
| Exploration and development of oil and gas properties | (26,225) | (36,503) | |||||||||
Cash flows provided by operating activities
Our cash flows for the three months ended March 31, 2020 and 2019 include cash receipts and disbursements attributable to our normal operating cycle. See Results of Operations above for more information on the factors driving these changes.
Cash flows used in investing activities
Expenditures for development of oil and natural gas properties are the primary use of our capital resources. The Company spent $26.2 million and $36.5 million on the exploration and development of oil and gas properties during the three months ended March 31, 2020 and 2019, respectively. The decrease in capital expenditures among the periods is primarily due to the reduced drilling and completion activity in response to the unprecedented drop in commodity prices in March 2020. The Company also spent $1.1 million less on acquisitions of oil and gas properties during the three months ended March 31, 2020 when compared to the same period in 2019.
Cash flows provided by financing activities
Net cash used in financing activities for the three months ended March 31, 2020 was $21.1 million, compared to cash provided by financing activities for the three months ended March 31, 2019 of $14.8 million. The change was primarily due to net payments on our Credit Facility during the three months ended March 31, 2020.
Non-GAAP Financial Measures
Adjusted EBITDAX represents earnings before interest, income taxes, depreciation, depletion, and amortization, exploration expense, and other non-cash and non-recurring charges. Adjusted EBITDAX excludes certain items that we believe affect the comparability of operating results and can exclude items that are generally non-recurring in nature or whose timing and/or amount cannot be reasonably estimated. Adjusted EBITDAX is a non-GAAP measure that we present because we believe it provides useful additional information to investors and analysts, as a performance measure, for analysis of our ability to internally generate funds for exploration, development, acquisitions, and to service debt. We are also subject to financial covenants under our Credit Facility based on adjusted EBITDAX ratios as further described Note 5 - Long-Term Debt in Part I, Item I of this document. In addition, adjusted EBITDAX is widely used by professional research analysts and others in the valuation, comparison, and investment recommendations of companies in the oil and gas exploration and production industry. Adjusted EBITDAX should not be considered in isolation or as a substitute for net income, income from operations, net cash provided by operating activities, or other profitability or liquidity measures prepared under GAAP. Because adjusted EBITDAX excludes some, but not all, items that affect net income (loss) and may vary among companies, the adjusted EBITDAX amounts presented may not be comparable to similar metrics of other companies.
26
The following table presents a reconciliation of the GAAP financial measure of net income to the non-GAAP financial measure of Adjusted EBITDAX (in thousands):
| Three Months Ended March 31, | ||||||||||||||
| 2020 | 2019 | |||||||||||||
| Net income (loss) | $ | 78,551 | $ | (6,993) | ||||||||||
| Exploration | 373 | 97 | ||||||||||||
| Depreciation, depletion, and amortization | 21,584 | 15,759 | ||||||||||||
| Amortization of deferred financing costs | — | 125 | ||||||||||||
| Abandonment and impairment of unproved properties | 30,057 | 879 | ||||||||||||
Stock-based compensation (1) | 1,239 | 1,380 | ||||||||||||
Severance costs (1) | 413 | 418 | ||||||||||||
| Gain on sale of properties, net | — | (1,126) | ||||||||||||
| Interest expense, net | 217 | 1,151 | ||||||||||||
| Derivative (gain) loss | (100,419) | 36,544 | ||||||||||||
| Derivative cash settlements | 11,254 | 936 | ||||||||||||
| Adjusted EBITDAX | $ | 43,269 | $ | 49,170 | ||||||||||
| _______________________________ | ||||||||||||||
(1) Included as a portion of general and administrative expense in the accompanying statements of operations. | ||||||||||||||
New Accounting Pronouncements
Please refer to Note 2 — Basis of Presentation under Part I, Item 1 of this report for any recently issued or adopted accounting standards.
Critical Accounting Policies and Estimates
Information regarding our critical accounting policies and estimates is contained in Part II, Item 7 of our 2019 Form 10-K.
Off-Balance Sheet Arrangements
Currently, we do not have any off-balance sheet arrangements that are not disclosed within this report.
Contractual Obligations
There have been no significant changes from our 2019 Form 10-K in our obligations and commitments, other than what is disclosed within Note 3 - Leases and Note 6 - Commitments and Contingencies under Part I, Item 1 of this report.
Cautionary Note Regarding Forward-Looking Statements
This Quarterly Report on Form 10-Q contains various statements, including those that express belief, expectation, or intention, as well as those that are not statements of historic fact, that are forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities and Exchange Act of 1934, as amended (the “Exchange Act”). When used in this Quarterly Report on Form 10-Q, the words “could,” “believe,” “anticipate,” “intend,” “estimate,” “expect,” “may,” “continue,” “predict,” “potential,” “project,” “plan,” “will,” and similar expressions are intended to identify forward-looking statements, although not all forward-looking statements contain such identifying words. These forward-looking statements are based on management's current belief, based on currently available information, as to the outcome and timing of future events.
Forward-looking statements include statements related to, among other things:
•the Company's business strategies;
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•reserves estimates;
•estimated sales volumes;
•amount and allocation of forecasted capital expenditures and plans for funding capital expenditures and operating expenses;
•ability to modify future capital expenditures;
•anticipated costs;
•compliance with debt covenants;
•ability to fund and satisfy obligations related to ongoing operations;
•compliance with government regulations, including environmental, health, and safety regulations and liabilities thereunder;
•adequacy of gathering systems and continuous improvement of such gathering systems;
•impact from the lack of available gathering systems and processing facilities in certain areas;
•impact of any pandemic or other public health epidemic, including the ongoing COVID-19 pandemic;
•natural gas, oil, and natural gas liquid prices and factors affecting the volatility of such prices;
•impact of lower commodity prices;
•sufficiency of impairments;
•the ability to use derivative instruments to manage commodity price risk and ability to use such instruments in the future;
•our drilling inventory and drilling intentions;
•impact of potentially disruptive technologies;
•our estimated revenue gains and losses;
•the timing and success of specific projects;
•our implementation of standard and long reach laterals;
•our use of multi-well pads to develop the Niobrara and Codell formations;
•intention to continue to optimize enhanced completion techniques and well design changes;
•stated working interest percentages;
•management and technical team;
•outcomes and effects of litigation, claims, and disputes;
•primary sources of future production growth;
•full delineation of the Niobrara B, C and Codell benches in our legacy, French Lake, and northern acreage;
•our ability to replace oil and natural gas reserves;
•our ability to convert PUDs to producing properties within five years of their initial proved booking;
•impact of recently issued accounting pronouncements;
•impact of the loss a single customer or any purchaser of our products;
•timing and ability to meet certain volume commitments related to purchase and transportation agreements;
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•the impact of customary royalty interests, overriding royalty interests, obligations incident to operating agreements, liens for current taxes, and other industry-related constraints;
•our financial position;
•our cash flow and liquidity;
•the adequacy of our insurance; and
•other statements concerning our operations, economic performance, and financial condition.
We have based these forward-looking statements on certain assumptions and analyses we have made in light of our experience and our perception of historical trends, current conditions, and expected future developments as well as other factors we believe are appropriate under the circumstances. They can be affected by inaccurate assumptions or by known or unknown risks and uncertainties. Many such factors will be important in determining actual future results. The actual results or developments anticipated by these forward-looking statements are subject to a number of risks and uncertainties, many of which are beyond our control, and may not be realized or, even if substantially realized, may not have the expected consequences. Actual results could differ materially from those expressed or implied in the forward-looking statements.
Factors that could cause actual results to differ materially include, but are not limited to, the following:
•the risk factors discussed in Part I, Item 1A of our Annual Report on Form 10-K for the year ended December 31, 2019 and in Part II, Item 1A of this report;
•further declines or volatility in the prices we receive for our oil, natural gas liquids, and natural gas;
•general economic conditions, whether internationally, nationally or in the regional and local market areas in which we do business;
•the effects of disruption of our operations or excess supply of oil and natural gas due to the COVID-19 pandemic and the actions by certain oil and natural gas producing countries;
•ability of our customers to meet their obligations to us;
•our access to capital;
•our ability to generate sufficient cash flow from operations, borrowings, or other sources to enable us to fully develop our undeveloped acreage positions;
•the presence or recoverability of estimated oil and natural gas reserves and the actual future sales volume rates and associated costs;
•uncertainties associated with estimates of proved oil and gas reserves;
•the possibility that the industry may be subject to future local, state, and federal regulatory or legislative actions (including additional taxes and changes in environmental regulation);
•environmental risks;
•seasonal weather conditions;
•lease stipulations;
•drilling and operating risks, including the risks associated with the employment of horizontal drilling and completion techniques;
•our ability to acquire adequate supplies of water for drilling and completion operations;
•availability of oilfield equipment, services, and personnel;
•exploration and development risks;
•operational interruption of centralized gas and oil processing facilities;
•competition in the oil and natural gas industry;
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•management’s ability to execute our plans to meet our goals;
•our ability to attract and retain key members of our senior management and key technical employees;
•our ability to maintain effective internal controls;
•access to adequate gathering systems and pipeline take-away capacity;
•our ability to secure adequate processing capacity for natural gas we produce, to secure adequate transportation for oil, natural gas, and natural gas liquids we produce, and to sell the oil, natural gas, and natural gas liquids at market prices;
•costs and other risks associated with perfecting title for mineral rights in some of our properties;
•continued hostilities in the Middle East, South America, and other sustained military campaigns or acts of terrorism or sabotage; and
•other economic, competitive, governmental, legislative, regulatory, geopolitical, and technological factors that may negatively impact our businesses, operations, or pricing.
All forward-looking statements speak only as of the date of this report. We disclaim any obligation to update or revise these statements unless required by law, and 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 Part II, Item 1A. Risk Factors and Part I, Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations and elsewhere in this report. These cautionary statements qualify all forward-looking statements attributable to us or persons acting on our behalf.
Item 3. Quantitative and Qualitative Disclosures About Market Risk.
Oil and Natural Gas Price Risk
Our financial condition, results of operations, and capital resources are highly dependent upon the prevailing market prices of oil and natural gas. These commodity prices are subject to wide fluctuations and market uncertainties due to a variety of factors that are beyond our control. Factors influencing oil and natural gas prices include the level of global demand for oil and natural gas, the global supply of oil and natural gas, the establishment of and compliance with production quotas by oil exporting countries, weather conditions which determine the demand for natural gas, the price and availability of alternative fuels, local and global politics, and overall economic conditions. It is impossible to predict future oil and natural gas prices with any degree of certainty. Sustained weakness in oil and natural gas prices may adversely affect our financial condition and results of operations, and may also reduce the amount of oil and natural gas reserves that we can produce economically. Any reduction in our oil and natural gas reserves, including reductions due to price fluctuations, can have an adverse effect on our ability to obtain capital for our exploration and development activities. Similarly, any improvements in oil and natural gas prices can have a favorable impact on our financial condition, results of operations, and capital resources.
Commodity Derivative Contracts
Our primary commodity risk management objective is to protect the Company’s balance sheet via the reduction in cash flow volatility. We enter into derivative contracts for oil, natural gas, and natural gas liquids using NYMEX futures or over-the-counter derivative financial instruments. The types of derivative instruments that we use include swaps, collars, and puts.
Upon settlement of the contract(s), if the relevant market commodity price exceeds our contracted swap price, or the collar’s ceiling strike price, we are required to pay our counterparty the difference for the volume of production associated with the contract. Generally, this payment is made up to 15 business days prior to the receipt of cash payments from our customers. This could have an adverse impact on our cash flows for the period between derivative settlements and payments for revenue earned.
While we may reduce the potential negative impact of lower commodity prices, we may also be prevented from realizing the benefits of favorable commodity price changes.
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Presently, our derivative contracts have been executed with seven counterparties, all of which are members of our Credit Facility syndicate. We enter into contracts with counterparties whom we believe are well capitalized. However, if our counterparties fail to perform their obligations under the contracts, we could suffer financial loss.
Please refer to the Note 10 - Derivatives in Part I, Item 1 of this report for summary derivative activity tables.
Interest Rates
As of both March 31, 2020 and the filing date of this report, we had $59.0 million outstanding under our Credit Facility. Borrowings under our Credit Facility bear interest at a fluctuating rate that is tied to an adjusted Base Rate or LIBOR, at our option. Any increases in these interest rates can have an adverse impact on our results of operations and cash flow. As of March 31, 2020, and through the filing date of this report, the Company was in compliance with all financial and non-financial covenants in the Credit Facility.
Counterparty and Customer Credit Risk
In connection with our derivatives activity, we have exposure to financial institutions in the form of derivative transactions. Seven members of our Credit Facility syndicate are counterparties on our derivative instruments currently in place and have investment grade credit ratings.
We are also subject to credit risk due to concentration of our oil and natural gas receivables with certain significant customers. The inability or failure of our significant customers to meet their obligations to us or their insolvency or liquidation may adversely affect our financial results. We review the credit rating, payment history, and financial resources of our customers, but we do not require our customers to post collateral.
Marketability of Our Production
The marketability of our production depends in part upon the availability, proximity, and capacity of third-party refineries, access to regional trucking, pipeline, and rail infrastructure, natural gas gathering systems, and processing facilities. We deliver crude oil and natural gas produced through trucking services, pipelines, and rail facilities that we do not own. The lack of availability or capacity on these systems and facilities could reduce the price offered for our production or result in the shut-in of producing wells or the delay or discontinuance of development plans for properties.
A portion of our production may also be interrupted, or shut in, from time to time for numerous other reasons, including as a result of accidents, weather, or field labor issues or strikes, or we might voluntarily curtail production in response to market conditions. If a substantial amount of our production is interrupted at the same time, it could adversely affect our cash flow.
Currently, there are no pipeline systems that service wells in our French Lake area of the Wattenberg Field. If neither we nor a third-party constructs the required pipeline system, we may not be able to fully test or develop our resources in French Lake.
There have not been material changes to the interest rate risk analysis or oil and gas price sensitivity analysis disclosed in our Annual Report on Form 10-K for the year ended December 31, 2019.
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Item 4. Controls and Procedures.
Evaluation of Disclosure Controls and Procedures
Our management, with the participation of our principal executive officer and principal financial officer, evaluated the effectiveness of our disclosure controls and procedures as of March 31, 2020. The term “disclosure controls and procedures,” as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act, means controls and other procedures of a company that are designed to ensure that information required to be disclosed by a company in the reports that it files or submits under the Exchange Act is recorded, processed, summarized, and reported, within the time periods specified in SEC rules and forms. Disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed by a company in the reports that it files or submits under the Exchange Act is accumulated and communicated to the company’s management, including its principal executive and principal financial officers and internal audit function, as appropriate, to allow timely decisions regarding required disclosure. Based on the evaluation of our disclosure controls and procedures as of March 31, 2020, our principal executive officer and principal financial officer concluded that, as of such date, our disclosure controls and procedures were effective at the reasonable assurance level.
Management recognizes that any controls and procedures, no matter how well designed and operated, can provide only reasonable assurance of achieving their objectives, and management necessarily applies its judgment in evaluating the cost-benefit relationship of possible controls and procedures. To assist management, we have established an internal audit function to verify and monitor our internal controls and procedures. The Company’s internal control system is supported by written policies and procedures, contains self-monitoring mechanisms, and is audited by the internal audit function. Appropriate actions are taken by management to correct deficiencies as they are identified.
Changes in Internal Control over Financial Reporting
There were no changes in our internal control over financial reporting identified in management’s evaluation pursuant to Rules 13a-15(d) or 15d-15(d) of the Exchange Act during the quarter ended March 31, 2020 that materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
PART II - OTHER INFORMATION
Item 1. Legal Proceedings.
From time to time, we are subject to legal proceedings and claims that arise in the ordinary course of business. Like other oil and gas producers and marketers, our operations are subject to extensive and rapidly changing federal and state environmental, health, and safety and other laws and regulations governing air emissions, wastewater discharges, and solid and hazardous waste management activities. As of the date of this filing, there were no probable, material pending or overtly threatened legal actions against us of which we were aware.
In February 2019, the Company was sent a notice of intent to sue (“NOI”) letter by WildEarth Guardians (“WEG”), an environmental non-governmental organization, alleging failure to obtain required permits under the federal Clean Air Act before constructing and operating well production facilities in the ozone non-attainment area around the Denver Metropolitan and North Front Range of Colorado, among other things. The Company is one of seven operators in the Wattenberg Field to receive such an NOI letter from WEG, and these letters appear to challenge long-established federal and state regulations and policies for permitting the construction and initial operation of upstream oil and gas production facilities in Colorado and elsewhere under the Clean Air Act and state counterpart statutes.
On May 3, 2019, WEG filed a lawsuit in the U.S. District Court for the District of Colorado against the Company and the other six operators who received the NOI, alleging claims consistent with those contained in the NOI letters. The allegations made in the lawsuit are based on novel and unprecedented interpretations of complex federal and state air quality laws and regulations. The Company has and will continue to vigorously defend against those allegations, and it will also coordinate as much as possible with state and federal permitting authorities to maintain the validity of its facilities’ current and future air permits. At this time, the Company is unable to estimate the lawsuit’s potential outcome.
There have been no other material changes to our legal proceedings from those described in our Annual Report on Form 10-K for the year ended December 31, 2019.
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Item 1A. Risk Factors.
Our business faces many risks. Any of the risk factors discussed in this report or our other SEC filings could have a material impact on our business, financial position, or results of operations. Additional risks and uncertainties not presently known to us or that we currently believe to be immaterial may also impair our business operation. For a discussion of our potential risks and uncertainties, see the risk factors in Part I, Item 1A in our Annual Report on Form 10-K for the year ended December 31, 2019, together with other information in this report and other reports and materials we file with the SEC. We have identified these risk factors as important factors that could cause our actual results to differ materially from those contained in any written or oral forward-looking statements made by us or on our behalf.
The extent to which the COVID-19 outbreak impacts our business, results of operations, and financial condition will depend on future developments, which cannot be predicted.
The outbreak of COVID-19, which has been declared by the World Health Organization to be a pandemic, has spread across the globe and is impacting worldwide economic activity, including the global demand for oil and natural gas. Any pandemic or other public health epidemic, including COVID-19, poses the risk that we or our employees, vendors, suppliers, customers, and other business partners may be prevented from conducting business activities for an indefinite period of time due to the potential spread of the disease within these groups or due to restrictions that may be requested or mandated by governmental authorities, including quarantines of certain geographic areas, restrictions on travel, and other restrictions that prohibit employees from going to work.
The COVID-19 pandemic has caused us to modify our business practices (including employee travel, employee work locations, and cancellation of physical participation in meetings, events, and conferences), and we may take further actions as may be required by government authorities or that we determine are in the best interests of our employees, vendors, suppliers, customers, and other business partners. There is no certainty that such measures will be sufficient to mitigate the risks posed by the virus or otherwise be satisfactory to government authorities.
The extent to which COVID-19 impacts our business, results of operations, and financial condition will depend on future developments, which are uncertain and cannot be predicted, including, but not limited to, the duration and spread of the outbreak, its severity, the actions to contain the virus or treat its impact, and how quickly and to what extent normal economic and operating conditions can resume. If COVID-19 continues to spread or the response to contain COVID-19 is unsuccessful, we could experience a material adverse effect on our business, financial condition, and results of operations. Even after the coronavirus outbreak has subsided, we may continue to experience materially adverse impacts to our business as a result of its global economic impact, including any recession that has occurred or may occur in the future.
The excess supply of oil and natural gas resulting from the reduced demand caused by the COVID-19 pandemic and the effects of actions by, or disputes among or between, oil and natural gas producing countries has resulted in transportation and storage constraints, and reductions of our planned production, and may cause shut-in of our wells, which could adversely affect our business, financial condition, and results of operations.
The recent worldwide outbreak of COVID-19, the uncertainty regarding the impact of COVID-19, and various governmental actions taken to mitigate the impact of COVID-19, have resulted in an unprecedented decline in demand for oil and natural gas. At the same time, the decision by Saudi Arabia in March 2020 to drastically reduce export prices and increase oil production, followed by curtailment agreements among OPEC and other countries, including Russia, has increased uncertainty and volatility around global oil supply-demand dynamics and further increased the excess supply of oil and natural gas. To the extent that the outbreak of COVID-19 continues to negatively impact demand, and OPEC members and other oil exporting nations fail to implement production cuts or other actions that are sufficient to support and stabilize commodity prices, we expect there to be excess supply of oil and natural gas for a sustained period. This excess supply has, in turn, resulted in transportation and storage capacity constraints in the United States, including in the DJ Basin where we operate, which may continue for a sustained period. For example, the substantial number of outstanding futures contracts, in conjunction with the market’s perception that crude oil storage in Cushing, Oklahoma was inadequate for May 2020 deliveries, caused NYMEX WTI prices to settle at a negative $37.63 per Bbl on April 20, 2020, a dynamic that has not previously occurred.
If, in the future, our ability to sell our production is hindered because of transportation or storage constraints, we may be required to shut-in or curtail production or flare our natural gas. Further, any prolonged shut-in of our wells may result in decreased well productivity once we are able to resume operations, and any cessation of drilling and development of our acreage could result in the expiration, in whole or in part, of our leases. All of these impacts resulting from the confluence of the COVID-19 pandemic and the price war between Saudi Arabia and Russia may adversely affect our business, financial condition, and results of operations.
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Due to the commodity price environment, we have postponed a significant portion of our developmental drilling. A sustained period of weakness in oil, natural gas, and NGLs prices, and the resultant effects of such prices on our drilling economics and ability to raise capital, will require us to reevaluate and further postpone or eliminate additional drilling. Such actions would likely result in the reduction of our PUDs and related PV-10 and a reduction in our ability to service our debt obligations. If we are required to further curtail our drilling program, we may be unable to continue to hold leases that are scheduled to expire, which may further reduce our reserves. As a result, if oil, natural gas and/or NGLs prices experience a sustained period of weakness, our future business, financial condition, results of operations, liquidity, and ability to finance planned capital expenditures may be materially and adversely affected.
Our production is not fully hedged, and we are exposed to fluctuations in oil, natural gas, and NGL prices and will be affected by continuing and prolonged declines in oil, natural gas, and NGL prices.
Our production is not fully hedged, and we are exposed to fluctuations in oil, natural gas, and NGL prices and will be affected by continuing and prolonged declines in oil, natural gas, and NGL prices. As of the filing date of this report, we have approximately 100% of our average 2020 guided oil production hedged and 33% of our average 2021 anticipated oil production hedged. We intend to continue to hedge our production, but we may not be able to do so at favorable prices. Accordingly, our revenues and cash flows are subject to increased volatility and may be subject to significant reduction in prices, which would have a material negative impact on our results of operations.
We cannot assure you that in connection with the spring 2020 semi-annual borrowing base redetermination, our borrowing base will not be reduced to a lesser amount than what we expect.
The borrowing base under our Credit Facility is redetermined on a semi-annual basis, as described in Note 5 – Credit Facility in Part I, Item 1 above. Despite a significant reduction in the assumed commodity prices used by the lenders to determine the value of our reserves, we do not expect that, in connection with the Credit Facility’s upcoming borrowing base redetermination, the borrowing base will be materially reduced. Approval of the borrowing base is subject to receiving consent from the lenders, and we cannot provide any assurance as to whether the borrowing base will be redetermined at an amount equal to or below its current level. If our borrowing base is redetermined to a substantially lower amount, we may be unable to obtain adequate funding under our Credit Facility, which could adversely affect our development plans as currently anticipated and could have a material adverse effect on our production, revenues, and results of operations.
If commodity prices continue to decrease or remain at current levels such that our future undiscounted cash flows from our properties are less than their carrying value, we may be required to take additional write-downs of the carrying values of our properties.
Accounting guidance requires that we periodically review the carrying value of our properties for possible impairment. Based on prevailing commodity prices and specific market factors and circumstances at the time of prospective impairment reviews, and the continuing evaluation of development plans, production data, economics, and other factors, we may be required to write-down the carrying value of our properties. A write-down constitutes a non-cash charge to earnings. Due to the recent depressed commodity prices, this quarter we recorded a $30.1 million abandonment and impairment of unproved properties. Further impairments, which could have an adverse effect on our results of operations, will be required if oil and natural gas prices further decline, unproved property values decrease, estimated proved reserve volumes are revised downward, or the net capitalized cost of proved oil and gas properties otherwise exceeds the present value of estimated future net cash flows.
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds.
Unregistered sales of securities. There were no sales of unregistered equity securities during the three month period ended March 31, 2020.
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Issuer purchases of equity securities. The following table contains information about acquisitions of our equity securities during the three month period ended March 31, 2020:
| Total Number of Shares | Maximum Number of | ||||||||||||||||||||||
| Total Number | Purchased as Part of | Shares that May Be | |||||||||||||||||||||
| of Shares | Average Price | Publicly Announced | Purchased Under Plans | ||||||||||||||||||||
Purchased(1) | Paid per Share | Plans or Programs | or Programs | ||||||||||||||||||||
| January 1, 2020 - January 31, 2020 | 1,631 | $ | 22.70 | — | — | ||||||||||||||||||
| February 1, 2020 - February 29, 2020 | 699 | $ | 18.15 | — | — | ||||||||||||||||||
| March 1, 2020 - March 31, 2020 | — | $ | — | — | — | ||||||||||||||||||
| Total | 2,330 | $ | 21.87 | — | — | ||||||||||||||||||
____________________________________________________________________________
(1)Represents shares that employees surrendered back to us that equaled in value the amount of taxes required for payroll tax withholding obligations upon the vesting of equity awards under the 2017 LTIP. These repurchases were not part of a publicly announced plan or program to repurchase shares of our common stock, nor do we have a publicly announced plan or program to repurchase shares of our common stock.
Our Credit Facility contains restrictions on the payment of dividends.
Item 3. Defaults Upon Senior Securities.
None.
Item 4. Mine Safety Disclosures.
Not applicable.
Item 5. Other Information.
None.
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Item 6. Exhibits.
| Exhibit No. | Description of Exhibit | |||||||
| 101.INS* | XBRL Instance Document | |||||||
| 101.SCH* | XBRL Taxonomy Extension Schema | |||||||
| 101.CAL* | XBRL Taxonomy Extension Calculation Linkbase | |||||||
| 101.DEF* | XBRL Taxonomy Extension Definition Linkbase | |||||||
| 101.LAB* | XBRL Taxonomy Extension Label Linkbase | |||||||
| 101.PRE* | XBRL Taxonomy Extension Presentation Linkbase | |||||||
| 104 | Cover Page Interactive Data File (formatted as Inline XBRL) | |||||||
* Filed with this report
** Furnished with this report
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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.
| BONANZA CREEK ENERGY, INC. | ||||||||||||||
| Date: | May 7, 2020 | By: | /s/ Eric T. Greager | |||||||||||
| Eric T. Greager | ||||||||||||||
| President and Chief Executive Officer | ||||||||||||||
| (principal executive officer) | ||||||||||||||
| By: | /s/ Brant DeMuth | |||||||||||||
| Brant DeMuth | ||||||||||||||
| Executive Vice President and Chief Financial Officer | ||||||||||||||
| (principal financial officer) | ||||||||||||||
| By: | /s/ Sandi K. Garbiso | |||||||||||||
| Sandi K. Garbiso | ||||||||||||||
| Vice President and Chief Accounting Officer | ||||||||||||||
| (chief accounting officer) | ||||||||||||||
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