bcei-20200930

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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 September 30, 2020

☐ 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 November 2, 2020, the registrant had 20,834,427 shares of common stock outstanding.

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BONANZA CREEK ENERGY, INC.

INDEX

PAGE

Part I.

FINANCIAL INFORMATION

Item 1.

Financial Statements

Condensed Consolidated Balance Sheets as of September 30, 2020 and December 31, 2019

Condensed Consolidated Statements of Operations and Comprehensive Income for the Three and Nine Months Ended September 30, 2020 and 2019

Condensed Consolidated Statements of Stockholders' Equity for the Three and Nine Months Ended September 30, 2020 and 2019

Condensed Consolidated Statements of Cash Flows for the Nine Months Ended September 30, 2020 and 2019

Notes to the Condensed Consolidated Financial Statements

Item 2.

Management’s Discussion and Analysis of Financial Condition and Results of Operations

Item 3.

Quantitative and Qualitative Disclosures About Market Risk

Item 4.

Controls and Procedures

Unregistered Sales of Equity Securities and Use of Proceeds

Item 3.

Defaults Upon Senior Securities

Item 4.

Mine Safety Disclosures

PART I - FINANCIAL INFORMATION

Item 1. Financial Statements.

BONANZA CREEK ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS (UNAUDITED)

(in thousands, except share amounts)


	September 30, 2020		December 31, 2019
ASSETS
Current assets:
Cash and cash equivalents	$	3,777	$	11,008
Accounts receivable, net:
Oil and gas sales	28,031		43,714
Joint interest and other	20,072		38,136
Prepaid expenses and other	3,562		7,048
Inventory of oilfield equipment	8,336		7,726
Derivative assets (note 10)	26,062		2,884
Total current assets	89,840		110,516
Property and equipment (successful efforts method):
Proved properties	1,052,004		935,025
Less: accumulated depreciation, depletion, and amortization	(192,701)		(126,614)
Total proved properties, net	859,303		808,411
Unproved properties	107,315		143,020
Wells in progress	50,911		98,750
Other property and equipment, net of accumulated depreciation of $3,601 in 2020 and $3,142 in 2019	3,375		3,394
Total property and equipment, net	1,020,904		1,053,575
Long-term derivative assets (note 10)	1,301		121
Right-of-use assets (note 3)	33,812		38,562
Other noncurrent assets	2,918		3,544
Total assets	$	1,148,775	$	1,206,318
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable and accrued expenses (note 4)	$	35,518	$	57,638
Oil and gas revenue distribution payable	17,918		29,021
Lease liability (note 3)	12,622		11,690
Derivative liability (note 10)	5,463		6,390
Total current liabilities	71,521		104,739
Long-term liabilities:
Credit facility (note 5)	20,000		80,000
Lease liability (note 3)	21,618		27,540
Ad valorem taxes	19,442		28,520
Derivative liability (note 10)	2,939		921
Deferred income taxes (note 12)	4,689		—
Asset retirement obligations for oil and gas properties (note 9)	25,614		27,908
Total liabilities	165,823		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, 20,834,028 and 20,643,738 issued and outstanding as of September 30, 2020 and December 31, 2019, respectively	4,282		4,284
Additional paid-in capital	705,537		702,173
Retained earnings	273,133		230,233
Total stockholders’ equity	982,952		936,690
Total liabilities and stockholders’ equity	$	1,148,775	$	1,206,318

The accompanying notes are an integral part of these condensed consolidated financial statements.

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BONANZA CREEK ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME (UNAUDITED)

(in thousands, except per share amounts)


	Three Months Ended September 30,				Nine Months Ended September 30,
	2020		2019		2020		2019
Operating net revenues:
Oil and gas sales	$	58,858	$	75,176	$	155,455	$	233,553
Operating expenses:
Lease operating expense	5,393		6,696		16,887		18,512
Midstream operating expense	3,970		3,271		11,338		8,301
Gathering, transportation, and processing	4,778		4,423		11,970		12,776
Severance and ad valorem taxes	(7,063)		6,738		1,588		18,697
Exploration	66		33		551		538
Depreciation, depletion, and amortization	23,439		19,900		67,306		54,557
Abandonment and impairment of unproved properties	223		879		30,589		2,636
Bad debt expense	102		—		678		—
General and administrative expense (including $1,723, $2,041, $4,436, and $5,189, respectively, of stock-based compensation)	8,919		9,920		26,754		30,001
Total operating expenses	39,827		51,860		167,661		146,018
Other income (expense):
Derivative gain (loss)	(10,670)		12,894		64,603		(15,477)
Interest expense, net	(356)		(322)		(1,557)		(1,858)
Loss on property transactions, net	—		—		(1,398)		(306)
Other income (expense)	(65)		5		(1,853)		28
Total other income (expense)	(11,091)		12,577		59,795		(17,613)
Income from operations before taxes	7,940		35,893		47,589		69,922
Income tax benefit (expense)	(4,689)		—		(4,689)		—
Net income	$	3,251	$	35,893	$	42,900	$	69,922

Comprehensive income	$	3,251	$	35,893	$	42,900	$	69,922

Net income per common share:
Basic	$	0.16	$	1.74	$	2.07	$	3.39
Diluted	$	0.16	$	1.74	$	2.06	$	3.38
Weighted-average common shares outstanding:
Basic	20,832		20,634		20,753		20,603
Diluted	20,903		20,678		20,826		20,671

The accompanying notes are an integral part of these condensed consolidated financial statements.

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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
Restricted common stock issued	228,149	—		—		—		—

Stock used for tax withholdings	(56,904)	(2)		(951)		—		(953)

Stock-based compensation	—	—		1,474		—		1,474
Net loss	—	—		—		(38,902)		(38,902)
Balances, June 30, 2020	20,826,327	4,282		703,874		269,882		978,038
Restricted common stock issued	10,849	—		—		—		—

Stock used for tax withholdings	(3,148)	—		(60)		—		(60)

Stock-based compensation	—	—		1,723		—		1,723
Net income	—	—		—		3,251		3,251
Balances, September 30, 2020	20,834,028	$	4,282	$	705,537	$	273,133	$	982,952


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
Restricted common stock issued	110,553	—		—		—		—

Stock used for tax withholdings	(36,145)	(1)		(930)		—		(931)

Stock-based compensation	—	—		1,768		—		1,768
Net income	—	—		—		41,022		41,022
Balances, June 30, 2019	20,632,999	4,285		698,526		197,195		900,006
Restricted common stock issued	2,178	—		—		—		—

Stock used for tax withholdings	(619)	(1)		(15)		—		(16)

Stock-based compensation	—	—		2,041		—		2,041
Net income	—	—		—		35,893		35,893
Balances, September 30, 2019	20,634,558	$	4,284	$	700,552	$	233,088	$	937,924

The accompanying notes are an integral part of these condensed consolidated financial statements.

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BONANZA CREEK ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(UNAUDITED)

(in thousands)


	Nine months ended September 30,
	2020		2019
Cash flows from operating activities:
Net income	$	42,900	$	69,922
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion, and amortization	67,306		54,557
Deferred income tax expense	4,689		—
Abandonment and impairment of unproved properties	30,589		2,636
Well abandonment costs and dry hole expense	(8)		62
Stock-based compensation	4,436		5,189
Non-cash lease component	(168)		—
Amortization of deferred financing costs	772		371
Derivative (gain) loss	(64,603)		15,477
Derivative cash settlements	42,494		3,766

Loss on property transactions, net	1,398		306
Other	(1,158)		(900)
Changes in current assets and liabilities:
Accounts receivable, net	24,262		(1,948)
Prepaid expenses and other assets	3,364		(1,180)
Accounts payable and accrued liabilities	(41,692)		16,785
Settlement of asset retirement obligations	(3,137)		(2,035)
Net cash provided by operating activities	111,444		163,008
Cash flows from investing activities:
Acquisition of oil and gas properties	(853)		(12,968)

Exploration and development of oil and gas properties	(56,216)		(184,119)
Proceeds from sale of oil and gas properties	—		1,153
Additions to property and equipment - non oil and gas	(440)		(292)
Net cash used in investing activities	(57,509)		(196,226)
Cash flows from financing activities:
Proceeds from credit facility	45,000		40,000
Payments to credit facility	(105,000)		(10,000)


Payment of employee tax withholdings in exchange for the return of common stock	(1,074)		(1,100)
Deferred financing costs	(13)		(226)
Principal payments on finance lease obligations	(71)		—
Net cash provided by (used in) financing activities	(61,158)		28,674
Net change in cash, cash equivalents, and restricted cash	(7,223)		(4,544)
Cash, cash equivalents, and restricted cash:
Beginning of period	11,095		13,002
End of period	$	3,872	$	8,458
Supplemental cash flow disclosure(1):
Cash paid for interest, net of capitalization	$	1,472	$	3,151
Severance and ad valorem tax refund	$	—	$	352
Receivables exchanged for additional interests in oil and gas properties	$	8,299	$	—
Changes in working capital related to drilling expenditures	$	610	$	20,592
(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.

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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 and nine months ended September 30, 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 September 30, 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.

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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 (“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 September 30, 2020 and December 31, 2019, the Company's receivables from contracts with customers were $28.0 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 September 30, 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 September 30,				Nine Months Ended September 30,
	2020		2019		2020		2019
Operating Revenues:
Crude oil sales	$	47,251	$	66,175	$	127,331	$	201,981
Natural gas sales	5,742		6,414		16,472		20,377
Natural gas liquids sales	5,865		2,587		11,652		11,195
Oil and gas sales	$	58,858	$	75,176	$	155,455	$	233,553

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 September 30,
	2020		2019
Cash and cash equivalents	$	3,777	$	8,371
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	$	3,872	$	8,458

__________________________

(1) Consists of funds for road maintenance and repairs.

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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 and nine months ended September 30, 2020, the Company incurred $0.2 million and $30.6 million, respectively, in abandonment and impairment of unproved properties due to the expiration of non-core leases and the reassessment of estimated probable and possible reserve locations based primarily upon economic viability. During the three and nine months ended September 30, 2019, the Company incurred $0.9 million and $2.6 million, respectively, 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 condensed consolidated financial statements. As of September 30, 2020, the Company has an allowance of $0.3 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 on the Company's condensed consolidated financial statements.

There are no other accounting standards applicable to the Company that would have a material effect on the Company's condensed consolidated financial statements and disclosures that have been issued, but not yet adopted by the Company as of September 30, 2020, and through the filing date of this report.

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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):


	September 30, 2020		December 31, 2019
Operating leases
Field equipment(1)	$	31,251	$	35,057
Corporate leases	1,756		2,462
Vehicles	586		1,043
Total right-of-use asset	$	33,593	$	38,562

Field equipment(1)	$	31,275	$	35,075
Corporate leases	2,255		3,129
Vehicles	562		1,026
Total lease liability	$	34,092	$	39,230

Finance leases
Right-of-use asset - field equipment(1)	$	219	$	—
Lease liability - field equipment(1)	$	148	$	—

__________________________

(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 various line items on the statements of operations or capitalized to oil and gas properties or other property and equipment, 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.

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The following table summarizes the components of the Company's gross lease costs incurred during the three and nine months ended September 30, 2020 and 2019 (in thousands):


	Three Months Ended September 30,				Nine Months Ended September 30,
	2020		2019		2020		2019
Operating lease cost(1)	$	3,462	$	3,088	$	10,560	$	8,124
Finance lease cost:
Amortization of right-of-use assets	6		—		13		—
Interest on lease liabilities	1		—		3		—
Short-term lease cost	129		2,153		2,011		5,975
Variable lease cost(2)	(89)		85		(133)		214
Sublease income(3)	(89)		(87)		(267)		(261)
Total lease cost	$	3,420	$	5,239	$	12,187	$	14,052

____________________________

(1) Includes office rent expense of $0.3 million for the three months ended September 30, 2020 and 2019 and $0.8 million for the nine months ended September 30, 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 has 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 September 30, 2020 are as follows:


	Operating Leases	Finance Leases
Weighted-average lease term (years)	3.02	0.41
Weighted-average discount rate	3.88%	3.47%

Supplemental cash flow information related to leases for the three and nine months ended September 30, 2020 and 2019 consisted of the following (in thousands):


	Three Months Ended September 30,				Nine Months Ended September 30,
	2020		2019		2020		2019
Cash paid for amounts included in the measurement of lease liabilities:
Operating cash flows from operating leases	$	3,187	$	2,705	$	9,599	$	7,071
Operating cash flows from finance leases	1		—		3		—
Financing cash flows from finance leases	31		—		71		—

Right-of-use assets obtained in exchange for new operating lease obligations	$	918	$	2,811	$	8,306	$	12,892
Right-of-use assets obtained in exchange for new finance lease obligations	—		—		219		—

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Future commitments by year for the Company's operating and finance leases with a lease term of one year or more as of September 30, 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	$	3,511	$	32
2021	13,239		118
2022	10,192		—
2023	6,593		—
2024	2,439		—
Thereafter	108		—
Total lease payments	36,082		150
Less: imputed interest	(1,990)		(2)
Total lease liability	$	34,092	$	148

NOTE 4 - ACCOUNTS PAYABLE AND ACCRUED EXPENSES

Accounts payable and accrued expenses contain the following (in thousands):



	As of September 30, 2020		As of December 31, 2019
Accrued drilling and completion costs	$	2,638	$	3,248
Accounts payable trade	3,229		17,117
Accrued general and administrative expense	3,654		5,620
Accrued lease operating expense	2,113		2,187
Accrued interest	6		692
Accrued oil and gas hedging	—		453
Accrued production and ad valorem taxes and other	23,878		28,321
Total accounts payable and accrued expenses	$	35,518	$	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 $750.0 million Credit Facility has a maturity date of December 7, 2023 and was governed by an initial borrowing base of $350.0 million. The Credit Facility borrowing base is redetermined on a semi-annual basis. The most recent redetermination was concluded on June 18, 2020, resulting in a reduction of the borrowing base and aggregate elected commitments to $260.0 million. The next scheduled redetermination is set to occur in November 2020 but was not completed as of the date of this filing.

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.

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Under the original terms of the Credit Facility, borrowings bore 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 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”) 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.

On June 18, 2020, in conjunction with the borrowing base redetermination, the Company, together with certain of its subsidiaries, entered into the First Amendment (the “First Amendment”) to the Credit Facility (as amended, restated, supplemented or otherwise modified) to, among other things: (i) implement certain anti-cash hoarding provisions, including a weekly mandatory prepayment requirement with respect to the excess of the Company's consolidated cash balance over $35.0 million; (ii) require that, in order to borrow or issue a letter of credit under the Credit Agreement, the consolidated cash balance not exceed the greater of $35.0 million (both before and after giving effect to such borrowing or letter of credit issuance), or expenditures in respect of oil and gas properties in the ordinary course of business (as agreed to by the administrative agent); (iii) decrease the maximum permitted net leverage ratio from 4.00 to 3.50 and the maximum permitted leverage ratio for purposes of making a restricted payment, restricted investment or optional or voluntary redemption from 3.25 to 2.75; (iv) increase the Eurodollar Rate margin to 2.00% to 3.00%; (v) increase the Reference Rate margin to 1.00% to 2.00% ; and (vi) amend certain other covenants and provisions. The Company was in compliance with all covenants as of September 30, 2020, and through the filing date of this report.

As of September 30, 2020 and December 31, 2019, the Company had $20.0 million and $80.0 million, respectively, outstanding on the Credit Facility. As of the date of this filing, the outstanding balance was $10.0 million. The Company's Credit Facility approximates fair value as the applicable interest rates are floating.

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) $0.8 million and $1.4 million as of September 30, 2020 and December 31, 2019, respectively, are presented within other noncurrent assets and (ii) $0.4 million and $0.5 million as of September 30, 2020 and December 31, 2019, respectively, are presented within the prepaid expenses and other line items in the accompanying balance sheets.

For the three months ended September 30, 2020 and 2019, the Company incurred interest expense of $0.7 million and $1.3 million, respectively. The Company capitalized $0.3 million and $1.0 million of interest expense during the three months ended September 30, 2020 and 2019, respectively. For the nine months ended September 30, 2020 and 2019, the Company incurred interest expense of $3.3 million and $3.6 million, respectively. The Company capitalized $1.7 million of interest expense during each of the nine months ended September 30, 2020 and 2019.

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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 was one of seven operators in the Wattenberg Field to receive such an NOI letter from WEG, and these letters appeared 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.

In May 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 were based on novel and unprecedented interpretations of complex federal and state air quality laws and regulations. The Company settled with WEG, and in September 2020 all claims in the lawsuit against the Company were dismissed with prejudice.

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 six-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 $56.7 million as of September 30, 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 three additional years.

The annual minimum commitment payments under the NGL Crude agreement for the next five years as of September 30, 2020 are presented below (in thousands):


	NGL Crude Commitments(1)
Remainder of 2020	$	3,694
2021	22,403
2022	23,097
2023	7,521
2024	—
2025 and thereafter	—
Total	$	56,715

____________________________

(1) The above calculation is based on the minimum volume commitment schedule (as defined in the NGL Crude agreement) and applicable differential fees.

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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 September 30,				Nine Months Ended September 30,
	2020		2019		2020		2019
Restricted stock units	$	1,350	$	1,535	$	3,935	$	3,966
Performance stock units	373		362		375		775
Stock options	—		144		126		448
Total stock-based compensation	$	1,723	$	2,041	$	4,436	$	5,189

As of September 30, 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	$	9,141	2023
Performance stock units	2,319		2022
	$	11,460

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.

During the nine months ended September 30, 2020, the Company granted 306,945 RSUs with a fair value of $4.9 million. A summary of the status and activity of non-vested restricted stock units for the nine months ended September 30, 2020 is presented below:


	Restricted Stock Units	Weighted-Average Grant-Date Fair Value
Non-vested, beginning of year	557,817	$	26.95
Granted	306,945	15.90
Vested	(252,672)	15.56
Forfeited	(54,547)	25.53
Non-vested, end of quarter	557,543	$	20.40

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.

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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 three-year performance period. The total number of PSUs granted is 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 annual return on average capital employed (“ROCE”) for each year during the three-year performance period. The split between the two performance criteria is even for the PSUs granted in 2018 and 2019, whereas the split is two-thirds weighted to the TSR criterion and one-third weighted to the ROCE criterion for the PSUs granted in 2020. 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 September 30, 2020, the Company does not expect any of the ROCE portion of the PSUs granted in 2018 and 2019 to vest and has accordingly adjusted the related compensation expense.

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.

During the nine months ended September 30, 2020, the Company granted 83,209 PSUs with a fair value of $1.9 million. A summary of the status and activity of performance stock units for the nine months ended September 30, 2020 is presented below:


	Performance Stock Units(1)	Weighted-Average Grant-Date Fair Value
Non-vested, beginning of year	153,470	$	24.74
Granted	83,209	23.22
Vested	—	—
Forfeited	—	—
Non-vested, end of quarter	236,679	$	24.21

___________________________

(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.

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There were no stock options granted during the nine months ended September 30, 2020. A summary of the status and activity of stock options for the nine months ended September 30, 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	(28,346)	34.36
Outstanding, end of quarter	72,368	$	34.36	6.6	$	—
Number of options outstanding and exercisable	72,368	$	34.36	6.6	$	—

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.

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. The following tables present the Company's 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 September 30, 2020
	Level 1		Level 2		Level 3
Derivative assets	$	—	$	27,363	$	—
Derivative liabilities	$	—	$	8,402	$	—


	As of December 31, 2019
	Level 1		Level 2		Level 3
Derivative assets	$	—	$	3,005	$	—
Derivative liabilities	$	—	$	7,311	$	—

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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 and nine months ended September 30, 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	(3,137)
Additions	84
Accretion expense	759

Ending balance as of September 30, 2020	$	25,614

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.

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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 September 30, 2020 and 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)		Natural Gas (CIG)
	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	MMBtu/day	Weighted Avg. Price per MMBtu
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	3,000	$43.67/$53.58	30,000	$2.25/$2.57	—	—	—	—
Swap	5,000	$54.48	—	—	20,000	$0.43	—	—
2Q21
Cashless Collar	2,500	$34.40/$49.82	20,000	$2.25/$2.52	—	—	—	—
Swap	4,000	$54.13	—	—	20,000	$0.43	—	—
3Q21
Cashless Collar	3,000	$30.00/$50.62	20,000	$2.25/$2.52	—	—	20,000	$2.15/$2.75
Swap	2,500	$54.45	—	—	20,000	$0.43	—	—
4Q21
Cashless Collar	4,000	$30.63/$50.34	20,000	$2.25/$2.52	—	—	20,000	$2.15/$2.75
Swap	1,000	$55.20	—	—	20,000	$0.43	—	—
1Q22
Cashless Collar	3,000	$30.83/$50.33	—	—	—	—	20,000	$2.15/$2.75

2Q22
Cashless Collar	1,500	$31.67/$54.79	—	—	—	—	20,000	$2.15/$2.75
3Q22
Cashless Collar	500	$35.00/$54.75	—	—	—	—	—	—

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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 as of the dates indicated in the table below (in thousands):


	September 30, 2020		December 31, 2019
Derivative Assets:
Commodity contracts - current	$	26,062	$	2,884
Commodity contracts - noncurrent	1,301		121
Derivative Liabilities:
Commodity contracts - current	(5,463)		(6,390)
Commodity contracts - noncurrent	(2,939)		(921)
Total derivative assets (liabilities), net	$	18,961	$	(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 September 30,				Nine months ended September 30,
	2020		2019		2020		2019
Derivative cash settlement gain (loss):
Oil contracts	$	9,165	$	2,424	$	42,088	$	3,518
Gas contracts	(538)		949		406		248
Total derivative cash settlement gain(1)	8,627		3,373		42,494		3,766
Change in fair value gain (loss)	(19,297)		9,521		22,109		(19,243)
Total derivative gain (loss)(1)	$	(10,670)	$	12,894	$	64,603	$	(15,477)

_______________________________

(1)Total derivative gain (loss) and total derivative cash settlement gain for the nine months ended September 30, 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 and warrants is based on the number of shares, if any, that would be exercisable at the end of the respective reporting period, assuming that date was the end of such stock options' or warrants' term.

Please refer to Note 7 - Stock-Based Compensation for additional discussion.

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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 September 30,				Nine Months Ended September 30,
	2020		2019		2020		2019
Net income	$	3,251	$	35,893	$	42,900	$	69,922

Basic net income per common share	$	0.16	$	1.74	$	2.07	$	3.39
Diluted net income per common share	$	0.16	$	1.74	$	2.06	$	3.38

Weighted-average shares outstanding - basic	20,832		20,634		20,753		20,603
Add: dilutive effect of contingent stock awards	71		44		73		68
Weighted-average shares outstanding - diluted	20,903		20,678		20,826		20,671

There were 549,967 and 393,783 shares that were anti-dilutive for the three months ended September 30, 2020 and 2019, respectively, and 427,857 and 155,094 shares that were anti-dilutive for the nine months ended September 30, 2020 and 2019, respectively.

The exercise price of the Company's stock options and warrants were in excess of the Company's stock price; therefore, they were excluded from the earnings per share calculation. The Company's warrants expired on April 30, 2020.

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 September 30, 2020 and December 31, 2019, a full valuation allowance should be established against the Company's deferred tax asset. During the three and nine months ended September 30, 2020, the Company recorded income tax expense and a related deferred tax liability of $4.7 million for projected taxable income in future periods in which only 80% of taxable income can be offset by net operating losses. During the three and nine months ended September 30, 2019, the Company recorded zero income tax expense. 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 September 30, 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.

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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 19% during the nine months ended September 30, 2020 when compared to the same period in 2019;

•Lease operating expense per Boe decreased by 17% for the nine months ended September 30, 2020 when compared to the same period in 2019;

•Crude oil equivalent sales volumes increased 10% for the nine months ended September 30, 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 $60.0 million to $20.0 million during the nine months ended September 30, 2020 from the $80.0 million outstanding at December 31, 2019;

•Total liquidity of $243.8 million at September 30, 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 nine months ended September 30, 2020 were $111.4 million, as compared to cash flows provided by operating activities of $163.0 million during the nine months ended September 30, 2019. Please refer to Liquidity and Capital Resources below for additional discussion; and

•Capital expenditures, inclusive of accruals, of $64.6 million during the nine months ended September 30, 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 $1.25 to $1.50 per barrel reduction to our oil differentials for barrels transported on such gathering line. Finally, the RMI 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 $153.8 million as of September 30, 2020.

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Outlook for 2020

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 Centers for Disease Control and Prevention. We have not yet experienced any material operational disruptions (including disruptions from our suppliers and service providers) as a result of a COVID-19 outbreak.

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, with a small amount of additional completion work done in July 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 drop in commodity prices, our named executive officers and independent directors 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 second 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.

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Results of Operations

The following table summarizes our product revenues, sales volumes, and average sales prices for the periods indicated:


	Three Months Ended September 30,
	2020		2019		Change		Percent Change
Revenues (in thousands):
Crude oil sales(1)	$	46,808	$	65,623	$	(18,815)	(29)	%
Natural gas sales(2)	4,803		5,399		(596)		(11)	%
Natural gas liquids sales	5,866		2,587		3,279		127	%
Product revenue	$	57,477	$	73,609	$	(16,132)	(22)	%

Sales Volumes:
Crude oil (MBbls)	1,284.0		1,277.8		6.2		—	%
Natural gas (MMcf)	3,629.3		3,423.3		206.0		6	%
Natural gas liquids (MBbls)	524.9		385.2		139.7		36	%
Crude oil equivalent (MBoe)(3)	2,413.8		2,233.6		180.2		8	%

Average Sales Prices (before derivatives)(4):
Crude oil (per Bbl)	$	36.45	$	51.36	$	(14.91)	(29)	%
Natural gas (per Mcf)	$	1.32	$	1.58	$	(0.26)	(16)	%
Natural gas liquids (per Bbl)	$	11.18	$	6.72	$	4.46	66	%
Crude oil equivalent (per Boe)(3)	$	23.81	$	32.96	$	(9.15)	(28)	%

Average Sales Prices (after derivatives)(4):
Crude oil (per Bbl)	$	43.59	$	53.25	$	(9.66)	(18)	%
Natural gas (per Mcf)	$	1.18	$	1.85	$	(0.67)	(36)	%
Natural gas liquids (per Bbl)	$	11.18	$	6.72	$	4.46	66	%
Crude oil equivalent (per Boe)(3)	$	27.39	$	34.47	$	(7.08)	(21)	%

_____________________________

(1)Crude oil sales excludes $0.4 million and $0.6 million of oil transportation revenues from third parties, which do not have associated sales volumes, for the three months ended September 30, 2020 and 2019, respectively.

(2)Natural gas sales excludes $1.0 million of gas gathering revenues from third parties, which do not have associated sales volumes, for each of the three months ended September 30, 2020 and 2019.

(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 September 30, 2020, the derivative cash settlement gain for oil contracts was $9.2 million, and the derivative cash settlement loss for natural gas contracts was $0.5 million. For the three months ended September 30, 2019, the derivative cash settlement gain for oil contracts was $2.4 million, and the derivative cash settlement gain for natural gas contracts was $0.9 million. Please refer to Note 10 - Derivatives of Part I, Item 1 of this report for additional disclosures.

Product revenues decreased by 22% to $57.5 million for the three months ended September 30, 2020 compared to $73.6 million for the three months ended September 30, 2019. The primary driver of the decrease in revenue is the $9.15 per Boe, or 28%, decrease in oil equivalent pricing, offset by an 8% increase in sales volumes. The increase in sales volumes is due to turning 26 gross wells to sales during the twelve-month period ending September 30, 2020.

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The following table summarizes our operating expenses for the periods indicated:


	Three Months Ended September 30,
	2020		2019		Change		Percent Change
Expenses (in thousands):
Lease operating expense	$	5,393	$	6,696	$	(1,303)	(19)	%
Midstream operating expense	3,970		3,271		699		21	%
Gathering, transportation, and processing	4,778		4,423		355		8	%
Severance and ad valorem taxes	(7,063)		6,738		(13,801)		(205)	%
Exploration	66		33		33		100	%
Depreciation, depletion, and amortization	23,439		19,900		3,539		18	%
Abandonment and impairment of unproved properties	223		879		(656)		(75)	%
Bad debt expense	102		—		102		100	%
General and administrative expense	8,919		9,920		(1,001)		(10)	%
Operating Expenses	$	39,827	$	51,860	$	(12,033)	(23)	%

Selected Costs ($ per Boe):
Lease operating expense	$	2.23	$	3.00	$	(0.77)	(26)	%
Midstream operating expense	1.64		1.46		0.18		12	%
Gathering, transportation, and processing	1.98		1.98		—		—	%
Severance and ad valorem taxes	(2.93)		3.02		(5.95)		(197)	%
Exploration	0.03		0.01		0.02		200	%
Depreciation, depletion, and amortization	9.71		8.91		0.80		9	%
Abandonment and impairment of unproved properties	0.09		0.39		(0.30)		(77)	%
Bad debt expense	0.04		—		0.04		100	%
General and administrative expense	3.70		4.44		(0.74)		(17)	%
Operating Expenses	$	16.49	$	23.21	$	(6.72)	(29)	%

Lease operating expense. Our lease operating expense decreased $1.3 million, or 19%, to $5.4 million for the three months ended September 30, 2020, from $6.7 million for the three months ended September 30, 2019, and decreased on a per Boe basis by 26%. The overall decrease was primarily due to reductions in compression costs, pumping and gauging costs, and several other areas implemented by the Company in a concerted effort to reduce costs in response to the decline in commodity pricing. Lease operating expense per unit decreased on a higher percentage basis due to oil equivalent sales volumes being 8% higher in the later period.

Midstream operating expense. Our midstream operating expense increased $0.7 million to $4.0 million for the three months ended September 30, 2020, from $3.3 million for the three months ended September 30, 2019, and increased 12% 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 during the three months ended September 30, 2019.

Gathering, transportation, and processing. Gathering, transportation, and processing expense increased by $0.4 million to $4.8 million for the three months ended September 30, 2020, from $4.4 million for the three months ended September 30, 2019. Natural gas and NGLs sales volumes have a direct correlation to gathering, transportation, and processing expense. Although natural gas and NGLs sales volumes increased 18% between the comparable periods, a decline in fees on sales contracts partially offset the increase in gathering, transportation, and processing expense.

Severance and ad valorem taxes. Our severance and ad valorem taxes decreased to a credit of $7.1 million for the three months ended September 30, 2020, from an expense of $6.7 million for the three months ended September 30, 2019. Severance and ad valorem taxes primarily correlate to revenues. Revenues decreased by 22% during the three months ended September 30, 2020 compared to the three months ended September 30, 2019. Additionally, we refined our tax estimate based on current mill levies, taxing districts, and company results based on commodity prices during the third quarter 2020, which resulted in a one-time adjustment of $12.6 million. Excluding this adjustment, our severance and ad valorem taxes were $5.5 million for the three months ended September 30, 2020.

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Depreciation, depletion, and amortization. Our depreciation, depletion, and amortization expense increased 18% to $23.4 million for the three months ended September 30, 2020, from $19.9 million for the three months ended September 30, 2019, and increased 9% on a per Boe basis during the comparable periods. The increase in depreciation, depletion, and amortization expense during the three months ended September 30, 2020 when compared to the three months ended September 30, 2019 is the result of (i) a $145.0 million increase in the depletable property base and (ii) an increase in the depletion rate driven by the increase in production between the comparable periods.

Abandonment and impairment of unproved properties. During the three months ended September 30, 2020 and 2019, the Company incurred $0.2 million and $0.9 million, respectively, in abandonment and impairment of unproved properties costs due to the expiration of non-core leases.

General and administrative. Our general and administrative expense decreased by $1.0 million or 10% for the three months ended September 30, 2020, compared to the three months ended September 30, 2019, and decreased by 17% on a per Boe basis between the comparable periods. The decrease in general and administrative expense is primarily due to a decrease in salaries, benefits, and stock compensation expense due to our reduced workforce, partially offset by advisor fees and severance costs totaling $1.0 million. General and administrative expense per Boe decreased on a higher percentage basis due to oil equivalent sales volumes being 8% higher during the three months ended September 30, 2020 as compared to the same period in 2019.

Derivative gain (loss). Our derivative loss for the three months ended September 30, 2020 was $10.7 million, as compared to a derivative gain of $12.9 million for the three months ended September 30, 2019. Our derivative loss is due to fair market value adjustments caused by market prices recovering from prior period levels, partially offset by settlement gains 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 September 30, 2020 and 2019 was $0.4 million and $0.3 million, respectively. Average debt outstanding for the three months ended September 30, 2020 and 2019 was $54.1 million and $84.9 million, respectively. The components of interest expense for the periods presented are as follows (in thousands):


	Three Months Ended September 30,
	2020		2019
Credit Facility	$	334	$	921
Commitment fees on available borrowing base under the Credit Facility	264		254
Amortization of deferred financing costs	92		123
Capitalized interest	(334)		(976)
Total interest expense, net	$	356	$	322

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The following table summarizes our product revenues, sales volumes, and average sales prices for the periods indicated:


	Nine Months Ended September 30,
	2020		2019		Change		Percent Change
Revenues (in thousands):
Crude oil sales(1)	$	125,956	$	200,153	$	(74,197)	(37)	%
Natural gas sales(2)	13,696		17,800		(4,104)		(23)	%
Natural gas liquids sales	11,652		11,195		457		4	%
Product revenue	$	151,304	$	229,148	$	(77,844)	(34)	%

Sales Volumes:
Crude oil (MBbls)	3,787.6		3,859.8		(72.2)		(2)	%
Natural gas (MMcf)	10,490.6		8,524.7		1,965.9		23	%
Natural gas liquids (MBbls)	1,399.9		1,042.2		357.7		34	%
Crude oil equivalent (MBoe)(3)	6,935.9		6,322.8		613.1		10	%

Average Sales Prices (before derivatives)(4):
Crude oil (per Bbl)	$	33.25	$	51.86	$	(18.61)	(36)	%
Natural gas (per Mcf)	$	1.31	$	2.09	$	(0.78)	(37)	%
Natural gas liquids (per Bbl)	$	8.32	$	10.74	$	(2.42)	(23)	%
Crude oil equivalent (per Boe)(3)	$	21.81	$	36.24	$	(14.43)	(40)	%

Average Sales Prices (after derivatives)(4):
Crude oil (per Bbl)	$	44.37	$	52.77	$	(8.40)	(16)	%
Natural gas (per Mcf)	$	1.34	$	2.12	$	(0.78)	(37)	%
Natural gas liquids (per Bbl)	$	8.32	$	10.74	$	(2.42)	(23)	%
Crude oil equivalent (per Boe)(3)	$	27.94	$	36.84	$	(8.90)	(24)	%

_____________________________

(1)Crude oil sales excludes $1.4 million and $1.8 million of oil transportation revenues from third parties, which do not have associated sales volumes, for of the nine months ended September 30, 2020 and 2019, respectively.

(2)Natural gas sales excludes $2.8 million and $2.6 million of gas gathering revenues from third parties, which do not have associated sales volumes, for the nine months ended September 30, 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 nine months ended September 30, 2020, the derivative cash settlement gain for oil contracts was $42.1 million, and the derivative cash settlement gain for natural gas contracts was $0.4 million. For the nine months ended September 30, 2019, the derivative cash settlement gain for oil contracts was $3.5 million, and the derivative cash settlement gain for natural gas contracts was $0.2 million. Please refer to Note 10 - Derivatives of Part I, Item 1 of this report for additional disclosures.

Product revenues decreased by 34% to $151.3 million for the nine months ended September 30, 2020 compared to $229.1 million for the nine months ended September 30, 2019. The primary driver of the decrease in revenue is the 40%, or $14.43 per Boe, decrease in oil equivalent pricing, offset by an 10% increase in sales volumes. The increase in sales volumes is due to turning 26 gross wells to sales during the twelve-month period ending September 30, 2020.

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The following table summarizes our operating expenses for the periods indicated:


	Nine Months Ended September 30,
	2020		2019		Change		Percent Change
Expenses (in thousands):
Lease operating expense	$	16,887	$	18,512	$	(1,625)	(9)	%
Midstream operating expense	11,338		8,301		3,037		37	%
Gathering, transportation, and processing	11,970		12,776		(806)		(6)	%
Severance and ad valorem taxes	1,588		18,697		(17,109)		(92)	%
Exploration	551		538		13		2	%
Depreciation, depletion, and amortization	67,306		54,557		12,749		23	%
Abandonment and impairment of unproved properties	30,589		2,636		27,953		1,060	%
Bad debt expense	678		—		678		100	%
General and administrative expense	26,754		30,001		(3,247)		(11)	%
Operating Expenses	$	167,661	$	146,018	$	21,643	15	%

Selected Costs ($ per Boe):
Lease operating expense	$	2.43	$	2.93	$	(0.50)	(17)	%
Midstream operating expense	1.63		1.31		0.32		24	%
Gathering, transportation, and processing	1.73		2.02		(0.29)		(14)	%
Severance and ad valorem taxes	0.23		2.96		(2.73)		(92)	%
Exploration	0.08		0.09		(0.01)		(11)	%
Depreciation, depletion, and amortization	9.70		8.63		1.07		12	%
Abandonment and impairment of unproved properties	4.41		0.42		3.99		950	%
Bad debt expense	0.10		—		0.10		100	%
General and administrative expense	3.86		4.74		(0.88)		(19)	%
Operating Expenses	$	24.17	$	23.10	$	1.07	5	%

Lease operating expense. Our lease operating expense decreased $1.6 million, or 9%, to $16.9 million for the nine months ended September 30, 2020, from $18.5 million for the nine months ended September 30, 2019, and 17% on a per Boe basis. The overall decrease was primarily due to lower pumping and gauging costs, compression costs, equipment rentals, and several other areas implemented by the Company in a concerted effort to reduce costs in response to the decline in commodity pricing, partially offset by an increase in salt water disposal costs. Lease operating expense per unit decreased on a higher percentage basis due to oil equivalent sales volumes being 10% higher in the later period.

Midstream operating expense. Our midstream operating expense increased $3.0 million to $11.3 million for the nine months ended September 30, 2020, from $8.3 million for the nine months ended September 30, 2019, and increased 24% 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 during the third quarter of 2019.

Gathering, transportation, and processing. Gathering, transportation, and processing expense decreased by $0.8 million to $12.0 million for the nine months ended September 30, 2020, from $12.8 million for the nine months ended September 30, 2019. Natural gas and NGLs sales volumes have a direct correlation to gathering, transportation, and processing expense. Although natural gas and NGLs sales volumes increased 28% during the nine months ended September 30, 2020 as compared to the nine months ended September 30, 2019, a decline 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 decreased 92% to $1.6 million for the nine months ended September 30, 2020, from $18.7 million for the nine months ended September 30, 2019. Severance and ad valorem taxes primarily correlate to revenues. Revenues decreased by 34% during the nine months ended September 30, 2020 compared to the nine months ended September 30, 2019. Additionally, we refined our tax estimate based on current mill levies, taxing districts, and company results based on commodity prices during the third quarter 2020, which resulted in a one-time adjustment of $12.6 million. Excluding this adjustment, our severance and ad valorem taxes were $14.2 million for the nine months ended September 30, 2020.

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Depreciation, depletion, and amortization. Our depreciation, depletion, and amortization expense increased 23% to $67.3 million for the nine months ended September 30, 2020, from $54.6 million for the nine months ended September 30, 2019, and increased 12% on a per Boe basis during the comparable periods. The increase in depreciation, depletion, and amortization expense during the nine months ended September 30, 2020 when compared to the nine months ended September 30, 2019 is the result of (i) a $145.0 million increase in the depletable property base and (ii) an increase in the depletion rate driven by an 10% increase in production between the comparable periods.

Abandonment and impairment of unproved properties. During the nine months ended September 30, 2020, the Company incurred $30.6 million in abandonment and impairment of unproved properties costs primarily due to the reassessment of estimated probable and possible reserve locations based primarily upon economic viability. In addition, during the nine months ended September 30, 2019, the Company incurred $2.6 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 $0.7 million for the nine months ended September 30, 2020, compared to the nine months ended September 30, 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 $3.2 million or 11% for the nine months ended September 30, 2020, compared to the nine months ended September 30, 2019, and decreased by 19% on a per Boe basis. The decrease in general and administrative expense between the comparable periods is primarily due to a decrease in salaries, benefits, and stock compensation expense due to our reduced workforce, partially offset by increased advisor fees and severance costs totaling $1.8 million. General and administrative expense per Boe decreased on a higher percentage basis due to oil equivalent sales volumes being 10% higher during the nine months ended September 30, 2020 as compared to the same period in 2019.

Derivative gain (loss). Our derivative gain for the nine months ended September 30, 2020 was $64.6 million, as compared to a derivative loss of $15.5 million for the nine months ended September 30, 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 nine months ended September 30, 2020 and 2019 was $1.6 million and $1.9 million, respectively. Average debt outstanding for the nine months ended September 30, 2020 and 2019 was $67.5 million and $71.6 million, respectively. The components of interest expense for the periods presented are as follows (in thousands):


	Nine Months Ended September 30,
	2020		2019
Credit Facility	$	1,701	$	2,433
Commitment fees on available borrowing base under the Credit Facility	785		792
Amortization of deferred financing costs	772		371
Capitalized interest	(1,701)		(1,738)
Total interest expense, net	$	1,557	$	1,858

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 September 30, 2020 and as of the filing date of this report. Consequently, the value of our commodity contracts as of September 30, 2020 was a net asset of $19.0 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 September 30, 2020, our liquidity was $243.8 million, consisting of $3.8 million of cash on hand and $240.0 million of available borrowing capacity on the Credit Facility.

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We anticipate and are on track to achieve a capital program of approximately $60.0 million to $70.0 million during 2020, which will allow us to maintain our reserve base while maintaining approximately flat production.

Our weighted-average interest rate on borrowings from the Credit Facility was 2.41% for the three months ended September 30, 2020. As of September 30, 2020 and the date of this filing, we had $20.0 million and $10.0 million, respectively, outstanding on our Credit Facility.

The following table summarizes our cash flows and other financial measures for the periods indicated (in thousands):


	Nine Months Ended September 30,
	2020		2019
Net cash provided by operating activities	$	111,444	$	163,008
Net cash used in investing activities	(57,509)		(196,226)
Net cash provided by (used in) financing activities	(61,158)		28,674
Cash, cash equivalents, and restricted cash	3,872		8,458
Acquisition of oil and gas properties	(853)		(12,968)
Exploration and development of oil and gas properties	(56,216)		(184,119)

Cash flows provided by operating activities

Our cash flows for the nine months ended September 30, 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 $56.2 million and $184.1 million on the exploration and development of oil and gas properties during the nine months ended September 30, 2020 and 2019, respectively. The decrease in capital expenditures between the periods is primarily due to reduced drilling and completion activity in response to the unprecedented drop in commodity prices between the comparable periods. The Company also spent $12.1 million less on acquisitions of oil and gas properties during the nine months ended September 30, 2020 when compared to the same period in 2019.

Cash flows provided by financing activities

Net cash used in financing activities for the nine months ended September 30, 2020 was $61.2 million, compared to cash provided by financing activities for the nine months ended September 30, 2019 of $28.7 million. The change was primarily due to a $90 million increase in net payments on our Credit Facility between the comparable periods.

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, and 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.

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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 September 30,				Nine Months Ended September 30,
	2020		2019		2020		2019
Net income	$	3,251	$	35,893	$	42,900	$	69,922
Exploration	66		33		551		538
Depreciation, depletion, and amortization	23,439		19,900		67,306		54,557
Amortization of deferred financing costs	—		—		—		248
Abandonment and impairment of unproved properties	223		879		30,589		2,636
Stock-based compensation (1)	1,723		2,041		4,436		5,189
Severance costs (1)	140		—		1,337		418
Advisor fees (1)	888		—		909		—
Loss on property transactions, net	—		—		1,398		306
Interest expense, net	356		322		1,557		1,858
Severance and ad valorem taxes adjustment (2)	(12,586)		—		(12,586)		—
Derivative (gain) loss	10,670		(12,894)		(64,603)		15,477
Derivative cash settlements	8,627		3,373		42,494		3,766
Income tax expense	4,689		—		4,689		—
Adjusted EBITDAX	$	41,486	$	49,547	$	120,977	$	154,915
_______________________________
(1) Included as a portion of general and administrative expense in the accompanying statements of operations.
(2) Included as a portion of severance and ad valorem taxes 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.

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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;

•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;

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•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;

•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;

•the scope, duration and severity of the COVID-19 pandemic, including any recurrence, as well as the timing of the economic recovery following the pandemic;

•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;

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•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;

•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.

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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.

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 September 30, 2020 and the filing date of this report, we had $20.0 million and $10.0 million, respectively, 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 September 30, 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 currently 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 September 30, 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 September 30, 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 September 30, 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.

As described above in Note 6 – Commitments and Contingencies, the litigation claims brought against the Company by WildEarth Guardians have been dismissed with prejudice

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. To date, the COVID-19 outbreak has surfaced in all regions around the world and has severely impacted the global economy, disrupted consumer spending and global supply chains, and created significant volatility and disruption of financial markets, all of which are expected to continue.

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, and may continue to result, 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 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, and may continue to result, 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 negative $37.63 per Bbl on April 20, 2020, a dynamic that has not previously occurred.

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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.

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.

As of the filing date of this report, we have approximately 100% of our average 2020 guided oil production hedged, approximately 50% of our average 2021 anticipated oil production hedged, and our hedging for 2022 oil production is even more limited. 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 fall 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. The most recent redetermination was concluded on June 18, 2020, resulting in a reduction of the borrowing base from $375.0 million to $260.0 million. The next scheduled redetermination is set to occur in November 2020 and was not completed as of the date of this filing. 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 year we recorded a $30.6 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.

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As a Colorado-only oil and gas operator, we face disproportionate risk associated with the long-term trend toward increased activism against oil and gas exploration and development activities in Colorado.

Opposition toward oil and gas drilling and development activity has been growing globally. Companies in the oil and gas industry are often the target of activist efforts from both individuals and non-governmental organizations regarding safety, environmental compliance, and business practices. Anti-development activists are working to, among other things, reduce access to federal and state government lands and delay or cancel certain projects such as the development of oil or gas shale plays. For example, environmental activists continue to advocate for increased regulations or bans on shale drilling in the United States, even in jurisdictions that are among the most stringent in their regulation of the industry. Further efforts could result in the following:

•delay or denial of drilling permits;

•revocation or modification of drilling permits or other necessary authorizations;

•shortening of lease terms or reduction in lease size;

•restrictions on installation or operation of production, gathering, or processing facilities;

•mandatory and lengthy distances between drilling locations and buildings and/or bodies of water or other protected areas;

•restrictions on the use of certain operating practices, such as hydraulic fracturing, or the disposal of related waste materials, such as hydraulic fracturing fluids and produced water;

•increased severance and/or other taxes;

•cyber-attacks;

•legal challenges or lawsuits;

•negative publicity about us or the oil and gas industry in general;

•increased costs of operations and development;

•reduction in demand for our products; and

•other adverse effects on our ability to develop our properties and expand production.

Specifically in Colorado, anti-development activity has both increased and become more effective in recent years. On April 16, 2019, new legislation became effective in Colorado, which substantially changed the state’s regulation of oil and gas exploration and production activities and applied immediately to all pending permit applications. The new law changed the mission of the Colorado Oil & Gas Conservation Commission (the “COGCC”) from “fostering” responsible and balanced development to “regulating” development to protect public health and the environment. The required composition of the COGCC was also changed to remove two seats for oil and gas industry experts and add experts on wildlife/environmental protection and public health. The state’s statutory pooling provisions were changed by the new law to require that an applicant own, or obtain the consent of, more than 45% of the applicable working or mineral interest, whereas previously the consent of only one mineral interest owner was required.

Among the most significant changes under the legislation was the provision of local government control over facility siting and surface impacts associated with oil and gas development. Whether an applicable local government determines to implement regulatory changes is optional, but if changes are adopted, the resulting regulations may be stricter than state requirements. Further, local governments may now inspect oil and gas operations and impose fines for leaks, spills, and emissions.

The legislation mandates the COGCC rulemaking on environmental protection, facility siting, cumulative impacts, flowlines, wells that are inactive, temporarily abandoned, or shut-in, financial assurance, wellbore integrity, and application fees. Pending the completion of this initial rulemaking, the COGCC may delay acting on selected permit applications.

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Further, on October 17, 2019, the Colorado Department of Public Health and Environment (the “CDPHE”) published a health risk assessment for oil and gas operations in Colorado. The assessment is based on modeling done with certain historic emissions data and found the possibility of negative short-term health impacts at distances out to 2,000 feet from facilities engaged in pre-production operations (i.e., drilling, completion, and flowback) under worst-case conditions. In response to the assessment, the COGCC announced that it will more rigorously scrutinize permit applications for wells within 2,000 feet of a building unit. The COGCC also announced that it will collect new data from oil and gas wells, compare the data to the assessment published by the CDPHE, and use the data to inform the COGCC’s new regulations and rulemakings.

The COGCC rulemaking process is ongoing. It appears likely that the COGCC will adopt final rules in November 2020 (effective January 1, 2020) that include an increased required setback of 2,000 feet between an oil and gas location and a residential or high occupancy building unit unless one or more conditions are satisfied to allow for a lesser setback that the COGCC determines is sufficiently protective of public health, safety and welfare, the environment, and wildlife resources. In addition, as part of proposed wildlife protections, the COGCC is contemplating an increased setback from 300 feet, as originally proposed by COGCC staff, to 500 feet between oil and gas locations and/or certain operations thereon and the ordinary high water mark for riparian resources and certain high priority aquatic habitats.

Permitting delays that occur while the COGCC rulemaking process proceeds, as well as delays that may result from the new COGCC rules and regulations themselves, could substantially curtail the Company’s near-term pace of new oil and gas development. We have already observed a marked decline in the pace at which permit applications are being granted, and if this trend continues, it could have a material adverse effect on our business, financial condition, and results of operations.

Additionally, the new legislation requires the state’s Air Quality Control Commission (the “AQCC”) to undertake rulemaking efforts to minimize methane emissions and emissions of other hydrocarbons, volatile organic compounds, and nitrogen oxides associated with certain oil and gas facilities. The AQCC may also adopt more stringent standards for leak detection and repair inspection frequency, pipeline and compressor station inspection and maintenance frequencies, installation of continuous emission monitoring equipment at certain oil and gas facilities, and reduced emissions from pneumatic devices. The legislation also grants the AQCC regulatory authority over a broad range of oil and gas facilities during pre-production activities, drilling, and completion.

Rules adopted by the COGCC and AQCC pursuant to the new legislation may significantly increase the Company’s operating costs and have a material adverse effect on our business, financial condition, and results of operations.

Additionally, anti-development activists succeeded in adding a measure to the November 6, 2018 ballot in Colorado, which sought to require a minimum 2,500 foot setback from occupied structures and vulnerable areas for all new oil and gas development on non-federal land. While this initiative was ultimately unsuccessful, had it been successful, it may have resulted in dramatically reducing the area of future oil and gas development in Colorado. Similar ballot measures were submitted for the 2020 election by anti-development activist groups. In addition, there have been several citizen/activist lawsuits filed against industry and state and local regulators associated with air quality, siting, environmental justice, and climate change. Such anti-development efforts are likely to continue in the future, which could result in dramatically reducing the area of future oil and gas development in Colorado or outright banning oil and gas development in Colorado. These efforts could have a material adverse effect on our business, financial condition, and results of operations.

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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 September 30, 2020.

Issuer purchases of equity securities. The following table contains information about acquisitions of our equity securities during the three month period ended September 30, 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
July 1, 2020 - July 31, 2020	2,810	$	19.07	—	—
August 1, 2020 - August 31, 2020	338	$	18.19	—	—
September 1, 2020 - September 30, 2020	—	$	—	—	—
Total	3,148	$	18.94	—	—

____________________________________________________________________________

(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

3.1		Third Amended and Restated Certificate of Incorporation of Bonanza Creek Energy, Inc. (incorporated by reference to Exhibit 3.1 to Bonanza Creek Energy, Inc.’s Registration Statement on Form 8-A filed on April 28, 2017).

3.2		Fourth Amended and Restated Bylaws of Bonanza Creek Energy, Inc. (incorporated by reference to Exhibit 3.2 to Bonanza Creek Energy, Inc.’s Registration Statement on Form 8-A filed on April 28, 2017).

31.1*		Certification of the Principal Executive Officer pursuant to Rule 13a-14(a).

31.2*		Certification of the Principal Financial Officer pursuant to Rule 13a-14(a).

32.1**		Certification of the Principal Executive Officer pursuant to 18.U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (furnished herewith).

32.2**		Certification of the Principal Financial Officer pursuant to 18.U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (furnished herewith).

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

†	Management Contract or Compensatory Plan or Agreement

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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:

November 5, 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)