Bonanza Creek Energy, Inc. (Form: 10-Q, Received: 08/08/2019 06:02:19)

Three Months Ended June 30, 2019

Six Months Ended June 30, 2019

Weighted-average lease term (years)

Weighted-average discount rate

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Table of Contents

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 June 30, 2019

☐ 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 and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted 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 and post 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	☐	(Do not check if a smaller reporting company)
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

Table of Contents

As of August 5, 2019, the registrant had 20,633,837 shares of common stock outstanding.

Table of Contents

BONANZA CREEK ENERGY, INC.

INDEX



			PAGE
Part I.	FINANCIAL INFORMATION

	Item 1.	Financial Statements

		Condensed Consolidated Balance Sheets as of June 30, 2019 and December 31, 2018	4

		Condensed Consolidated Statements of Operations and Comprehensive Income for the Three and Six Months Ended June 30, 2019 and 2018	5

		Condensed Consolidated Statements of Stockholders' Equity for the Three and Six Months Ended June 30, 2019 and 2018	6

		Condensed Consolidated Statements of Cash Flows for the Six Months Ended June 30, 2019 and 2018	7

		Notes to the Condensed Consolidated Financial Statements	8

	Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	22

	Item 3.	Quantitative and Qualitative Disclosures About Market Risk	34

	Item 4.	Controls and Procedures	35

Part II.	OTHER INFORMATION

	Item 1.	Legal Proceedings	36

	Item 1A.	Risk Factors	36

	Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	37

	Item 3.	Defaults Upon Senior Securities	38

	Item 4.	Mine Safety Disclosures	38

	Item 5.	Other Information	38

	Item 6.	Exhibits	38

Table of Contents

PART I - FINANCIAL INFORMATION

Item 1. Financial Statements.

BONANZA CREEK ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS (UNAUDITED)

(in thousands, except share amounts)



	June 30, 2019			December 31, 2018
ASSETS
Current assets:
Cash and cash equivalents	$	9,149		$	12,916
Accounts receivable:
Oil and gas sales	40,341			31,799
Joint interest and other	23,946			47,577
Prepaid expenses and other	5,336			4,633
Inventory of oilfield equipment	2,946			3,478
Derivative assets (note 10)	11,116			34,408
Total current assets	92,834			134,811
Property and equipment (successful efforts method):
Proved properties	802,452			719,198
Less: accumulated depreciation, depletion and amortization	(86,265		)	(52,842		)
Total proved properties, net	716,187			666,356
Unproved properties	155,882			154,352
Wells in progress	133,364			93,617
Other property and equipment, net of accumulated depreciation of $2,853 in 2019 and $2,546 in 2018	3,490			3,649
Total property and equipment, net	1,008,923			917,974
Long-term derivative assets (note 10)	1,176			3,864
Right-of-use assets (note 3)	38,623			—
Other noncurrent assets	3,782			4,885
Total assets	$	1,145,338		$	1,061,534
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable and accrued expenses (note 4)	$	45,087		$	79,390
Oil and gas revenue distribution payable	30,262			19,903
Current portion of lease liability (note 3)	10,593			—
Derivative liability (note 10)	2,066			183
Total current liabilities	88,008			99,476

Long-term liabilities:
Credit facility (note 5)	65,000			50,000
Lease liability (note 3)	28,792			—
Ad valorem taxes	34,370			18,740
Asset retirement obligations for oil and gas properties (note 9)	29,162			29,405
Total liabilities	245,332			197,621

Commitments and contingencies (note 6)	—			—

Stockholders’ equity:
Preferred stock, $.01 par value, 25,000,000 shares authorized, none outstanding	—			—
Common stock, $.01 par value, 225,000,000 shares authorized, 20,632,999 and 20,543,940 issued and outstanding as of June 30, 2019 and December 31, 2018, respectively	4,285			4,286
Additional paid-in capital	698,526			696,461
Retained earnings	197,195			163,166
Total stockholders’ equity	900,006			863,913
Total liabilities and stockholders’ equity	$	1,145,338		$	1,061,534

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 June 30,						Six Months Ended June 30,
	2019			2018			2019			2018
Operating net revenues:
Oil and gas sales	$	85,783		$	71,872		$	158,377		$	136,064
Operating expenses:
Lease operating expense	6,390			11,316			11,816			21,775
Gas plant and midstream operating expense	2,709			3,247			5,030			6,860
Gathering, transportation, and processing	4,331			1,660			8,353			3,998
Severance and ad valorem taxes	7,711			6,071			11,959			11,303
Exploration	408			221			505			250
Depreciation, depletion, and amortization	18,898			9,564			34,657			17,072
Abandonment and impairment of unproved properties	878			2,477			1,757			4,979
Unused commitments	—			—			—			21
General and administrative expense (including $1,768, $2,184, $3,148, and $3,192, respectively, of stock-based compensation)	9,803			9,917			20,081			19,451
Total operating expenses	51,128			44,473			94,158			85,709
Income from operations	34,655			27,399			64,219			50,355
Other income (expense):
Derivative gain (loss)	8,173			(22,012		)	(28,371		)	(30,754		)
Interest expense	(385		)	(805		)	(1,536		)	(1,162		)
Loss on sale of properties, net	(1,432		)	—			(306		)	—
Other income	11			277			23			290
Total other income (expense)	6,367			(22,540		)	(30,190		)	(31,626		)
Income from operations before taxes	41,022			4,859			34,029			18,729
Income tax benefit (expense)	—			—			—			—
Net income	$	41,022		$	4,859		$	34,029		$	18,729

Comprehensive income	$	41,022		$	4,859		$	34,029		$	18,729

Basic net income per common share	$	1.99		$	0.24		$	1.65		$	0.91

Diluted net income per common share	$	1.99		$	0.24		$	1.65		$	0.91

Basic weighted-average common shares outstanding	20,618			20,488			20,588			20,471

Diluted weighted-average common shares outstanding	20,664			20,603			20,630			20,538

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			Retained
	Common Stock					Paid-In			Earnings
	Shares		Amount			Capital			(Deficit)			Total
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



Balances, December 31, 2017	20,453,549		$	4,286	$	689,068		$	(5,020	)	$	688,334
Restricted common stock issued	107			—		—			—			—
Stock used for tax withholdings	(37	)		—		—			—			—
Stock-based compensation	—			—		1,008			—			1,008
Net income	—			—		—			13,870			13,870
Balances, March 31, 2018	20,453,619			4,286		690,076			8,850			703,212
Restricted common stock issued	78,002			—		—			—			—
Stock used for tax withholdings	(24,013	)		—		(794	)		—			(794	)
Exercise of stock options	27,191			—		968			—			968
Stock-based compensation	—			—		2,184			—			2,184
Net income	—			—		—			4,859			4,859
Balances, June 30, 2018	20,534,799		$	4,286	$	692,434		$	13,709		$	710,429

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)



	Six months ended June 30,
	2019			2018
Cash flows from operating activities:
Net income	$	34,029		$	18,729
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion, and amortization	34,657			17,072
Abandonment and impairment of unproved properties	1,757			4,979
Well abandonment costs and dry hole expense	62			—
Stock-based compensation	3,148			3,192
Amortization of deferred financing costs	248			—
Derivative loss	28,371			30,754
Derivative cash settlements	393			(11,622		)
Loss on sale of properties, net	306			—
Other	(901		)	172
Changes in current assets and liabilities:
Accounts receivable	15,089			(20,376		)
Prepaid expenses and other assets	(703		)	935
Accounts payable and accrued liabilities	(10,833		)	(889		)
Settlement of asset retirement obligations	(1,175		)	(797		)
Net cash provided by operating activities	104,448			42,149
Cash flows from investing activities:
Acquisition of oil and gas properties	(11,738		)	(1,295		)
Exploration and development of oil and gas properties	(111,398		)	(91,482		)
Proceeds from sale of oil and gas properties	1,153			20
Additions to property and equipment - non oil and gas	(148		)	(280		)
Net cash used in investing activities	(122,131		)	(93,037		)
Cash flows from financing activities:
Proceeds from Current Credit Facility	15,000			—
Proceeds from Prior Credit Facility	—			60,000
Proceeds from exercise of stock options	—			968
Payment of employee tax withholdings in exchange for the return of common stock	(1,083		)	(794		)
Net cash provided by financing activities	13,917			60,174
Net change in cash, cash equivalents, and restricted cash	(3,766		)	9,286
Cash, cash equivalents, and restricted cash:
Beginning of period	13,002			12,782
End of period	$	9,236		$	22,068
Supplemental cash flow disclosure:
Cash paid for interest, net of capitalization	$	1,190		$	906
Severance and ad valorem tax refund	$	352		$	—
Changes in working capital related to drilling expenditures	$	(8,763	)	$	1,909
Cash paid for amounts included in the measurement of lease liabilities	$	4,366		$	—

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. Interim results of operations are not necessarily indicative of the results to be expected for the full fiscal year.

The financial information as of December 31, 2018, has been derived from the audited financial statements contained in our Annual Report on Form 10-K for the year ended December 31, 2018 (“2018 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 2018 Form 10-K. The Company follows the same accounting principles for preparing quarterly and annual reports.

Principles of Consolidation

The 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.

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. Virtually all of our 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”, known as the “NGL 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 agreement based on approved production plans to determine if liquidated damages to NGL are probable. As of June 30, 2019, the Company believes that the volumes delivered to NGL 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 agreement.

Under our oil sales contracts we sell oil production at the wellhead, or other contractually agreed-upon delivery points, and collect an agreed-upon index price, net of pricing differentials. In this scenario, we recognize revenue when control transfers to the purchaser at the wellhead, or other contractually agreed-upon delivery point, at the net contracted price received.

Under our natural gas processing contracts, we deliver 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

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for the resulting sales of NGLs and residue gas. For the contracts where we maintain control through the outlet of the midstream processing facility, we recognize revenue on a gross basis, with gathering, transportation, and processing fees presented as an expense in our 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, we recognize revenue on a net basis.

Under our product sales contracts, we invoice customers once our performance obligations have been satisfied, at which point payment is unconditional. Accordingly, our product sales contracts do not give rise to contract assets or liabilities under this guidance. At June 30, 2019 and December 31, 2018, our receivables from contracts with customers were $40.3 million and $31.8 million, respectively.

Revenue attributable to each of our identified revenue streams is disaggregated below (in thousands):



	Three Months Ended June 30,				Six Months Ended June 30,
	2019		2018		2019		2018
Operating Revenues:
Crude oil sales	$	75,016	$	60,751	$	135,806	$	112,714
Natural gas sales	6,507		$	4,938	13,964		11,159
Natural gas liquids sales	4,260		6,183		8,607		12,191
Oil and gas sales	$	85,783	$	71,872	$	158,377	$	136,064

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 June 30,
	2019		2018
Cash and cash equivalents	$	9,149	$	21,989
Restricted cash included in other noncurrent assets	87		79
Total cash, cash equivalents, and restricted cash as shown in the statements of cash flows	$	9,236	$	22,068

Restricted cash consists of funds for road maintenance and repairs.

Accounting Pronouncements Recently Adopted and Issued

In February 2016, the FASB issued Update No. 2016-02 - Leases (ASC 842) to increase transparency and comparability among organizations by recognizing right-of-use assets and lease liabilities on the balance sheet and disclosing key information about leasing arrangements. Each lease that is recognized in the balance sheet will be classified as either finance or operating requiring certain quantitative and qualitative disclosures. Leases acquired to explore the development of oil and natural gas resources are not within the scope of this guidance. The new standard was adopted using the optional transition approach at the date of initial application on January 1, 2019. Please refer to Note 3 - Leases for additional disclosure.

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 is effective for fiscal years beginning after December 15, 2019, including interim periods within those fiscal years, with early adoption permitted, and shall be applied using a modified retrospective approach resulting in a cumulative effect adjustment to retained earnings upon adoption. Historically, the Company's credit losses on oil and natural gas sales receivables and joint interest receivables have not been significant, and the Company does not believe the adoption of this standard will have a material impact on its consolidated financial statements.

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

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measurement disclosures. This update is effective for annual periods beginning after December 15, 2019, and interim periods within those annual periods. The standard will only impact the form of the Company's disclosures.

There are no other accounting standards applicable to the Company that would have a material effect on the Company’s financial statements and disclosures that have been issued but not yet adopted by the Company as of June 30, 2019, and through the filing date of this report.

NOTE 3 - LEASES

On January 1, 2019, the Company adopted ASC 842 using the optional transition approach prescribed in Updated No 2018-11 - Lease (Topic 842), Targeted Improvements. Under this approach, results for reporting periods beginning January 1, 2019, are presented in accordance with ASC 842, while prior period amounts are reported in accordance with ASC 840 - Leases. The Company recognized $32.8 million and $33.6 million in right-of-use assets and lease liabilities, respectively, on January 1, 2019, representing minimum payment obligations associated with compressors, vehicles, office space, and other field and corporate equipment with contractual durations in excess of one year. There was no cumulative-effect adjustment to retained earnings upon adoption of the new standard.

ASC 842 provided certain practical expedients, of which the Company elected (i) to account for lease and non-lease components in its contracts as a single lease component for all asset classes, (ii) to adopt the land easement practical expedient, which allows the Company to apply ASC 842 prospectively to new or modified land easements beginning January 1, 2019, and (iii) to not apply the recognition requirements of ASC 842 to leases with a lease term of twelve months or less. The Company's leasing activities as a lessor are negligible.

During the three and six months ended June 30, 2019, the Company incurred $8.9 million and $10.1 million, respectively, in new right-of-use assets and lease liabilities. The Company’s right-of-use assets and lease liabilities are recognized at their discounted present value on the balance sheet at $38.6 million and $39.4 million as of June 30, 2019, respectively. All leases recognized on the Company's balance sheet are classified as operating leases, which include leases related to the asset classes reflected in the table below (in thousands):



		Right-of-use Asset		Lease Liability
Field equipment⁽¹⁾	$	34,712	$	34,712
Corporate leases		2,987		3,749
Vehicles		924		924
Total	$	38,623	$	39,385

____________________________

(1) Includes compressors, certain gas processing equipment, and other field equipment.

The lease amounts disclosed are presented on a gross basis. A portion of these costs may have been or will be billed to other working interest owners, and the Company's net share of these costs once paid are included in proved properties, other property and equipment, lease operating expenses, or general and administrative expenses, as applicable.

The Company recognizes lease expense on a straight-line basis excluding short-term and variable lease payments, which 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.

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



		Three Months Ended June 30, 2019			Six Months Ended June 30, 2019
Operating lease cost⁽¹⁾	$	2,686		$	5,036
Short-term lease cost		2,000			3,822
Variable lease cost⁽²⁾		109			129
Sublease income⁽³⁾		(87	)		(174	)
Total lease cost	$	4,708		$	8,813

____________________________

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(1) Includes office rent expense of $0.3 million and $0.5 million for the three and six months ended June 30, 2019, respectively.

(2) Variable lease cost represents differences between minimum lease obligations and actual costs incurred for certain leases that do not have fixed payments related to both lease and non-lease components. Such incremental costs include lease payment increases or decreases driven by market price fluctuations and leased asset maintenance costs.

(3) The Company subleased a portion of its office space for the remainder of the office lease term.

The Company does not have any leases with an implicit interest rate that can be readily determined. As a result, the Company used the incremental borrowing rate, based on the Current 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's weighted-average lease term and discount rate used during the three and six months ended June 30, 2019 are as follows:

Minimum future commitments by year for the Company's long-term operating leases as of June 30, 2019 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):



		Amount
Remainder of 2019	$	6,081
2020		11,831
2021		10,659
2022		8,911
2023		4,477
Thereafter		690
Total lease payments		42,649
Less: imputed interest		(3,264	)
Total lease liability	$	39,385

Future minimum lease payments related to the Company’s operating leases as of December 31, 2018 are presented below (in thousands):



		Amount
2019	$	1,256
2020		1,351
2021		1,401
2022		234
2023		—
2024 and thereafter		—
Total	$	4,242

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NOTE 4 - ACCOUNTS PAYABLE AND ACCRUED EXPENSES

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



	As of June 30, 2019		As of December 31, 2018
Accrued drilling and completion costs	$	24,839	$	33,602
Accounts payable trade	6,593		11,532
Accrued general and administrative expense	2,726		12,728
Accrued lease operating expense	2,700		2,183
Accrued interest	587		241
Accrued oil and gas hedging	45		—
Accrued production and ad valorem taxes and other	7,597		19,104
Total accounts payable and accrued expenses	$	45,087	$	79,390

NOTE 5 - LONG-TERM DEBT

Current 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 “Current Credit Facility”). The Current Credit Facility has an aggregate original commitment amount of $750.0 million, an initial borrowing base of $350.0 million, and matures on December 7, 2023. The Current Credit Facility borrowing base is redetermined on a semi-annual basis, with the most recent being concluded on May 16, 2019 resulting in an increase in the borrowing base to $375.0 million; however, the Company chose to hold the aggregate elected commitments at $350.0 million. The next scheduled redetermination is set to occur in November 2019.

Borrowings under the Current Credit Facility bear interest at a per annum rate equal to, at the option of the Company, either (i) a London InterBank Offered Rate (“LIBOR”), subject to a 0% LIBOR floor plus a margin of 1.75% to 2.75%, based on the utilization of the Current 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 Current Credit Facility (the “Reference Rate”). Interest on borrowings that bear interest at the Eurodollar Rate shall be payable on the last day of the applicable interest period selected by the Company, which shall be one, two, three, or six months, and interest on borrowings that bear interest at the Reference Rate shall be payable quarterly in arrears. The Company's Current Credit Facility approximates fair value as the applicable interest rates are floating.

The Current Credit Facility is guaranteed by all wholly-owned subsidiaries of the Company (each, a “Guarantor” and, together with the Company, the “Credit Parties”), and is secured by first priority security interests on substantially all assets of each Credit Party, subject to customary exceptions.

The Current Credit Facility contains customary representations and affirmative covenants. The Current 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 Current Credit Facility, including, without limitation, tested on the last day of each fiscal quarter, (i) a maximum ratio of the Company’s consolidated indebtedness (subject to certain exclusions) to earnings before interest, income taxes, depreciation, depletion, and amortization, exploration expense, and other non-cash charges (“EBITDAX”) of 4.00 to 1.00 and (ii) a current ratio, as defined in the agreement, inclusive of the unused Commitments then available to be borrowed, to not be less than 1.00 to 1.00. The Company was in compliance with all covenants as of June 30, 2019, and through the filing date of this report.

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The Company had $65.0 million and $50.0 million outstanding on the Current Credit Facility as of June 30, 2019 and December 31, 2018, respectively. As of the date of filing, the Company had $80.0 million outstanding on its Current Credit Facility.

In connection with the Current Credit Facility, the Company capitalized a total of $2.5 million in deferred financing costs, of which $1.7 million and $0.5 million of the total post amortization net capitalized amounts are presented within other noncurrent assets and prepaid expenses and other line items, respectively, in the accompanying condensed consolidated balance sheets (“balance sheets”) as of June 30, 2019 and December 31, 2018, respectively.

Prior Credit Facility

Upon emergence from bankruptcy, the Company entered into a revolving credit facility, as the borrower, with KeyBank National Association, as the administrative agent, and certain lenders party thereto (the “Prior Credit Facility”). The borrowing base was $191.7 million and had a maturity date of March 31, 2021.

The Prior Credit Facility stated the Company's leverage ratio of indebtedness to EBITDAX was not to exceed 3.50 to 1.00, the minimum current ratio had to be 1.00 to 1.00, and the minimum interest coverage ratio of trailing twelve-month EBITDAX to trailing twelve-month interest expense had to be 2.50 to 1.00 as of the end of the respective fiscal quarter. During the period the Prior Credit Facility was outstanding, the Company was in compliance with all covenants.

The Prior Credit Facility provided for interest rates plus an applicable margin to be determined based on LIBOR or a base rate, at the Company’s election. LIBOR borrowings bore interest at LIBOR, plus a margin of 3.00% to 4.00% depending on the utilization level, and the base rate borrowings bore interest at the Reference Rate, as defined in the Prior Credit Facility, plus a margin of 2.00% to 3.00% depending on the utilization level.

This Prior Credit Facility was terminated and settled in full as of December 7, 2018.

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 GAAP, 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 material pending or overtly threatened legal actions against the Company of which it is aware.

As previously described in its 2018 Form 10-K, the Company and the Colorado Department of Public Health and Environment (“CDPHE”) agreed to a Compliance Order on Consent (the “COC”) resolving the matters addressed by a compliance advisory issued to the Company for certain storage tank facilities located in the Wattenberg Field with respect to applicable air quality regulations. The COC further set forth compliance requirements and criteria for continued operations. The Company adopted procedures and processes to address the monitoring, reporting, and control of air emissions. In order to be in compliance, the Company has incurred approximately $1.6 million from 2017 through June 30, 2019 and expects to incur an immaterial amount of maintenance during the remainder of 2019 through 2022. The COC can be terminated after four years with a showing of substantial compliance and CDPHE approval.

In February 2019, the Company was sent a notice of intent to sue (“NOI”) letter by WildEarth Guardians (“WEG”), an environmental non-governmental organization, alleging failure to obtain required permits under the federal Clean Air Act before constructing and operating well production facilities in the ozone non-attainment area around the Denver Metropolitan and North Front Range of Colorado, among other things. The Company is one of seven operators in the Wattenberg Field to receive such an NOI letter from WEG, and these letters appear to challenge long-established federal and state regulations and

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policies for permitting the construction and initial operation of upstream oil and gas production facilities in Colorado and elsewhere under the Clean Air Act and state counterpart statutes.

On May 3, 2019, WEG filed a lawsuit against the Company and the other six operators who received the NOI, alleging claims consistent with those contained in the NOI letters. Because the allegations made in the lawsuit are based on novel and unprecedented interpretations of complex federal and state air quality laws and regulations, it is not possible for the Company to determine at this time whether the allegations have merit, but the Company will vigorously defend against such allegations and will coordinate as much as possible with state and federal permitting authorities to maintain the validity of its current and future air permits for such facilities.

Commitments

The purchase agreement to deliver fixed determinable quantities of crude oil to NGL became effective on April 28, 2017. The NGL agreement includes defined volume commitments over an initial seven-year term. Under the terms of the NGL agreement, the Company will be required to make periodic deficiency payments for any shortfalls in delivering minimum gross volume commitments, which are set in six-month periods beginning in January 2018. During 2018, the average minimum gross volume commitment was approximately 10,100 barrels per day, and the minimum gross volume commitment increased by approximately 41% from 2018 to 2019 and will increase approximately 3% each year thereafter 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, based on the minimum gross volume commitment schedule (as defined in the agreement) and the applicable differential fee, is $88.5 million as of June 30, 2019. Upon notifying NGL at least twelve months prior to the expiration date of the NGL agreement, the Company may elect to extend the term of the NGL agreement for up to three additional years.

The annual minimum commitment payments under the NGL agreement for the next five years as of June 30, 2019 are presented below (in thousands):



		NGL Gross Commitments(1)
2019	$	10,043
2020		22,487
2021		21,278
2022		21,790
2023		12,946
2024 and thereafter		—
Total	$	88,544

_______________________________

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

Since the commencement of the NGL agreement and through the remainder of 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 2018 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. Upon emergence from bankruptcy, the Company reserved 2,467,430 shares of the new common stock for issuance under the 2017 LTIP. See below for further discussion of awards granted under the 2017 LTIP.

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

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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 six months ended June 30, 2019, the Company granted 251,000 RSUs with a fair value of $5.7 million. Total compensation expense recorded for RSUs, inclusive of grants to the members of the Board, for the three and six months ended June 30, 2019 was $1.3 million and $2.4 million, respectively. As of June 30, 2019, unrecognized compensation expense for RSUs was $13.4 million and will be amortized through 2023.

A summary of the status and activity of non-vested restricted stock units is presented below:



	Restricted Stock Units		Weighted- Average Grant-Date Fair Value
Non-vested at beginning of year	480,835		$	30.83
Granted	251,000		$	22.76
Vested	(128,642	)	$	23.50
Forfeited	(5,090	)	$	33.22
Non-vested at end of quarter	598,103		$	26.99

Cash flows resulting from excess tax benefits are to be classified as part of cash flows from operating activities. Excess tax benefits are realized tax benefits from tax deductions for vested restricted stock in excess of the deferred tax asset attributable to stock compensation costs for such restricted stock. The Company recorded no excess tax benefits for the periods presented.

Performance Stock Units

The 2017 LTIP allows for the issuance of PSUs to employees at the sole discretion of the Board. The number of shares of the Company’s common stock that may be issued to settle PSUs range 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 evenly split between two performance criterion. The first criterion is based on a comparison of the Company’s absolute and relative total shareholder return (“TSR”) for the performance period compared with the TSRs of a group of peer companies for the same performance period. The TSR for the Company and each of the peer companies is determined by dividing (A)(i) the volume-weighted average share price for the last 30 trading days of the performance period, minus (ii) the volume-weighted average share price for the 30 trading days preceding the beginning of the performance period, by (B) the volume-weighted average share price for the 30 trading days preceding the beginning of the performance period. The second criterion is based on the Company's average annual return on capital employed (“ROCE”) for each year during the three-year performance period. Compensation expense associated with PSUs is recognized as general and administrative expense over the performance period.

The fair value of the PSUs was measured at the grant date with 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 PSUs, 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 six months ended June 30, 2019, the Company granted 102,379 PSUs to certain officers with a fair value of $2.3 million. Total compensation expense recorded for PSUs for the three and six months ended June 30, 2019 was $0.3 million and $0.4 million, respectively. As of June 30, 2019, unrecognized compensation costs for PSUs was $3.0 million and will be amortized through 2021.

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A summary of the status and activity of performance stock units is presented below:



	Performance Stock Units		Weighted- Average Grant-Date Fair Value
Non-vested at beginning of year⁽¹⁾	53,689		$	29.92
Granted⁽¹⁾	102,379		$	22.15
Vested⁽¹⁾	(2,598	)	$	23.55
Forfeited⁽¹⁾	—		$	—
Non-vested at end of quarter ⁽¹⁾	153,470		$	24.74

___________________________


(1)	The number of awards assumes that the associated performance condition is met at the target amount. The final number of shares of the Company’s common stock issued may vary depending on the performance multiplier, which ranges from zero to two, depending on the level of satisfaction of the performance condition.

Stock Options

The 2017 LTIP allows for the issuance of stock options to the Company's employees at the sole discretion of the Board of Directors. Options expire ten years from the grant date unless otherwise determined by the Board of Directors. Compensation expense on the stock options is recognized as general and administrative expense over the vesting period of the award.

There were no stock options granted during the six months ended June 30, 2019. Total expense recorded for stock options for the three and six months ended June 30, 2019 was $0.1 million and $0.3 million, respectively. As of June 30, 2019, unrecognized compensation cost for stock options was $0.5 million and will be amortized through 2020.

Stock options are valued using a Black-Scholes Model where 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, 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 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.

A summary of the status and activity of non-vested stock options is presented below:



	Stock Options		Weighted- Average Exercise Price		Weighted-Average Remaining Contractual Term (in years)	Aggregate Intrinsic Value (in thousands)
Outstanding at beginning of year	132,809		$	34.36	6.7	$	—
Granted	—		—		—	$	—
Exercised	—		—		—	$	—
Forfeited	(27,018	)	$	34.36	—	$	—
Outstanding at end of quarter	105,791		$	34.36	7.8	$	—
Number of options outstanding and exercisable	70,524		$	34.36	7.8	$	—

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

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Level 3: Significant inputs to the valuation model are unobservable

The following tables present the Company's financial and non-financial assets and liabilities that were accounted for at fair value and their classification within the fair value hierarchy (in thousands):



	As of June 30, 2019
	Level 1		Level 2		Level 3
Derivative assets⁽¹⁾	$	—	$	12,292	$	—
Derivative liabilities⁽¹⁾	$	—	$	2,066	$	—



	As of December 31, 2018
	Level 1		Level 2		Level 3
Derivative assets⁽¹⁾	$	—	$	38,272	$	—
Derivative liabilities⁽¹⁾	$	—	$	183	$	—
Asset retirement obligations⁽²⁾	$	—	$	—	$	1,490

____________________________


(1)	This represents a financial asset or liability that is measured at fair value on a recurring basis.


(2)	Represents the revision to estimates of the asset retirement obligation, which is a non-financial liability that is measured at fair value on a nonrecurring basis. Please refer to the Asset Retirement Obligation section below for additional discussion.

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 and collars 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.

Asset Retirement Obligation

The Company utilizes the income valuation technique to determine the fair value of the asset retirement obligation liability at the point of inception by applying a credit-adjusted risk-free rate, which takes into account the Company’s credit risk, the time value of money, and the current economic state, to the undiscounted expected abandonment cash flows. Upon completion of wells, the Company records an asset retirement obligation at fair value using Level 3 assumptions. Given the unobservable nature of the inputs, the initial measurement of the asset retirement obligation liability is deemed to use Level 3 inputs. There were no asset retirement obligations measured at fair value as of June 30, 2019. The Company had $1.5 million of asset retirement obligations recorded at fair value as of December 31, 2018.

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, which ranges from 5% to 7%.

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A roll-forward of the Company's asset retirement obligation is as follows (in thousands):



		Amount
Beginning balance as of December 31, 2018	$	29,405
Liabilities settled		(1,145	)
Additions		79
Accretion expense		823
Ending balance as of June 30, 2019	$	29,162

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, puts, and collars for oil and natural gas, and none of the derivative instruments qualifies as having hedging relationships.

In a typical commodity swap agreement, if the agreed upon published third-party index price is lower than the swap fixed price, the Company receives the difference between the index price and the agreed upon swap fixed price. If the index price is higher than the swap fixed 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.

A basis swap arrangement guarantees a price differential from a specified delivery 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.

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As of June 30, 2019, the Company had entered into the following commodity derivative contracts:



	Crude Oil (NYMEX WTI)		Natural Gas (CIG)
	Bbls/day	Weighted Avg. Price per Bbl	MMBtu/day	Weighted Avg. Price per MMBtu
3Q19
Cashless Collar	4,000	$58.13/$75.54	—	—
Swap	5,000	$59.92	22,500	$2.13
4Q19
Cashless Collar	4,000	$58.13/$75.54	—	—
Swap	5,000	$59.92	22,500	$2.13
1Q20
Cashless Collar	5,000	$55.00/$62.88	—	—
Swap	3,000	$63.48	2,500	$2.40
2Q20
Cashless Collar	5,000	$55.00/$63.33	—	—
3Q20
Cashless Collar	2,000	$55.00/$63.14	—	—
4Q20
Cashless Collar	2,000	$55.00/$63.14	—	—

As of the filing date of this report, the Company had entered into the following commodity derivative contracts:



	Crude Oil (NYMEX WTI)		Natural Gas (CIG Basis)		Natural Gas (CIG)
	Bbls/day	Weighted Avg. Price per Bbl	MMBtu/day	Weighted Avg. Basis Differential to CIG Price per MMBtu	MMBtu/day	Weighted Avg. Price per MMBtu
3Q19
Cashless Collar	4,000	$58.13/$75.54	—	—	—	—
Swap	5,000	$59.92	—	—	22,500	$2.13
4Q19
Cashless Collar	4,000	$58.13/$75.54	—	—	—	—
Swap	5,000	$59.92	—	—	22,500	$2.13
1Q20
Cashless Collar	5,000	$55.00/$62.88	—	—	—	—
Swap	3,000	$63.48	5,000	$0.60	2,500	$2.40
2Q20
Cashless Collar	6,000	$55.00/$62.45	—	—	—	—
Swap	—	—	5,000	$0.60	—	—
3Q20
Cashless Collar	3,000	$55.00/$61.42	—	—	—	—
Swap	—	—	5,000	$0.60	—	—
4Q20
Cashless Collar	3,000	$55.00/$61.42	—	—	—	—
Swap	—	—	5,000	$0.60	—	—

Derivative Assets and Liabilities Fair Value

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The Company’s commodity derivatives are measured at fair value and are included in the accompanying balance sheets as derivative assets and liabilities. The following table contains a summary of all the Company’s derivative positions reported on the accompanying balance sheets for the periods below (in thousands):



		As of June 30, 2019			As of December 31, 2018
	Balance Sheet Location	Fair Value			Fair Value
Derivative Assets:
Commodity contracts	Current assets	$	11,116		$	34,408
Commodity contracts	Noncurrent assets	1,176			3,864
Derivative Liabilities:
Commodity contracts	Current liabilities	(2,066		)	(183		)
Commodity contracts	Long-term liabilities	—			—
Total derivative assets, net		$	10,226		$	38,089

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 June 30,						Six months ended June 30,
	2019			2018			2019			2018
Derivative cash settlement gain (loss):
Oil contracts	$	(984	)	$	(7,319	)	$	1,094		$	(11,825	)
Gas contracts	441			9			(701		)	203
Total derivative cash settlement gain (loss)⁽¹⁾	$	(543	)	$	(7,310	)	$	393		$	(11,622	)

Change in fair value liability	8,716			(14,702		)	(28,764		)	(19,132		)

Total derivative gain (loss)⁽¹⁾	$	8,173		$	(22,012	)	$	(28,371	)	$	(30,754	)

_______________________________


(1)	Total derivative gain (loss) and total derivative cash settlement gain (loss) for the three and six months ended June 30, 2019 and 2018 are reported in the derivative loss line item and derivative cash settlements line item in the accompanying statements of cash flows, within 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 range from zero to two times the number of PSUs granted on the award date. The number of potentially dilutive shares related to PSUs is based on the number of shares, if any, that would be issuable at the end of the respective reporting period, assuming that date was the end of the performance period applicable to such PSUs. The Company issued stock options and warrants, which both represent the right to purchase the Company's common stock at a specified price. The number of potentially dilutive shares related to the stock options is based on the number of shares, if any, that would be exercised at the end of the respective reporting period, assuming that date was the end of such stock options' term. The number of potentially dilutive shares related to the warrants is based on the number of shares, if any, that would be exercisable at the end of the respective reporting period.

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

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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 June 30,				Six Months Ended June 30,
	2019		2018		2019		2018
Net income	$	41,022	$	4,859	$	34,029	$	18,729

Basic net income per common share	$	1.99	$	0.24	$	1.65	$	0.91

Diluted net income per common share	$	1.99	$	0.24	$	1.65	$	0.91

Weighted-average shares outstanding - basic	20,618		20,488		20,588		20,471
Add: dilutive effect of unvested stock awards	46		115		42		67
Weighted-average shares outstanding - diluted	20,664		20,603		20,630		20,538

There were 329,755 and 181,762 shares that were anti-dilutive for the three months ended June 30, 2019 and 2018, respectively, and 160,770 and 196,435 shares that were anti-dilutive for the six months ended June 30, 2019 and 2018, respectively.

The exercise price of the Company's warrants was in excess of the Company's stock price; therefore, they were excluded from the earnings per share calculation.

NOTE 12 - INCOME TAXES

The Company has fully implemented the Tax Cuts and Jobs Act, which made significant changes to U.S. federal income tax law, including a reduction in the federal corporate tax rate to 21%, effective January 1, 2018.

The Company uses the asset and liability method of accounting for deferred income taxes. Deferred tax assets and liabilities are determined based on the temporary differences between the financial statement and tax basis of assets and liabilities. Deferred tax assets or liabilities at the end of each period are determined using the tax rate in effect at that time. There is a full valuation allowance on the Company's net deferred tax asset causing the Company’s current rate to differ from the U.S. statutory income tax rate.

As of June 30, 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 2019.

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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, 2018, 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 DJ Basin. We intend to continue the development of our reserves and increase production on our multi-year inventory of identified potential drilling locations and through potential mergers and acquisitions that meet our strategic and financial objectives. 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:


•	Lease operating expense decreased $4.9 million or $4.03 per Boe for the three months ended June 30, 2019 when compared to the same period during 2018, which included our Mid-Continent assets that were sold on August 6, 2018;


•	General and administrative expense per Boe decreased by 27% for the three months ended June 30, 2019 when compared to the same period during 2018;


•	Crude oil equivalent sales volumes increased 36% for the three months ended June 30, 2019 when compared to the same period during 2018;


•	Total liquidity of $294.1 million at June 30, 2019, consisting of cash on hand plus funds available under our Current Credit Facility. Please refer to Liquidity and Capital Resources below for additional discussion;


•	Cash flows provided by operating activities for the six months ended June 30, 2019 was $104.4 million, as compared to cash flows provided by operating activities of $42.1 million during the six months ended June 30, 2018. Please refer to Liquidity and Capital Resources below for additional discussion;


•	Incurred capital expenditures, inclusive of accruals, of $126.5 million during the six months ended June 30, 2019; and


•	Operations of the Company’s new oil gathering line to Riverside Terminal commenced in July and, as reflected in our annual guidance, is expected to lower corresponding oil differentials in the second half of 2019 by $1.25 - $1.50 per barrel.

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 provides cost economies of a centralized system. The RMI system reduces gathering system pressures at the wellhead, 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, the system reduces facility site footprints, leading to more cost-efficient operations and reduced surface disturbance. The net book value of the Company's RMI assets was $134.6 million as of June 30, 2019.

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Outlook for 2019

The Company's 2019 capital budget of $230.0 million to $255.0 million assumes a continuous one-rig development pace. The drilling and completion portion of the budget is expected to be approximately $210.0 million to $220.0 million, which will support drilling 59 gross wells and turning to sales 45 gross wells. Included in the drilling and completion budget is $15.0 million for non-operated capital expenditures. Of the operated wells planned to be drilled, approximately 26 are extended reach lateral (“XRL”) wells and 33 are standard reach lateral (“SRL”) wells. Of the wells planned to be completed, 16 are XRL wells, five are medium reach lateral (“MRL”) wells, and 24 are SRL wells. The remaining 2019 capital budget of $20.0 million to $35.0 million is to support infrastructure and leasehold costs. Actual capital expenditures could vary significantly based on, among other things, development pace, market conditions, commodity prices, drilling and completion costs, well results, acquisitions or divestitures, and changes in the borrowing base under our Current Credit Facility.

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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 June 30,
	2019		2018		Change			Percent Change
Revenues (in thousands):
Crude oil sales⁽¹⁾	$	74,319	$	60,640	$	13,679		23	%
Natural gas sales⁽²⁾		5,629		4,629		1,000		22	%
Natural gas liquids sales ⁽³⁾		4,260		6,183		(1,923	)	(31	)%
Product revenue	$	84,208	$	71,452	$	12,756		18	%

Sales Volumes:
Crude oil (MBbls)⁽⁴⁾		1,373.8		952.4		421.4		44	%
Natural gas (MMcf)⁽⁵⁾		2,903.0		2,177.8		725.2		33	%
Natural gas liquids (MBbls)⁽⁶⁾		365.4		324.6		40.8		13	%
Crude oil equivalent (MBoe)⁽³⁾		2,223.0		1,640.0		583.0		36	%

Average Sales Prices (before derivatives)⁽⁷⁾:
Crude oil (per Bbl)	$	54.10	$	63.67	$	(9.57	)	(15	)%
Natural gas (per Mcf)	$	1.94	$	2.13	$	(0.19	)	(9	)%
Natural gas liquids (per Bbl)	$	11.66	$	19.05	$	(7.39	)	(39	)%
Crude oil equivalent (per Boe)⁽³⁾	$	37.88	$	43.57	$	(5.69	)	(13	)%

Average Sales Prices (after derivatives)⁽⁷⁾:
Crude oil (per Bbl)	$	53.38	$	55.99	$	(2.61	)	(5	)%
Natural gas (per Mcf)	$	2.09	$	2.13	$	(0.04	)	(2	)%
Natural gas liquids (per Bbl)	$	11.66	$	19.05	$	(7.39	)	(39	)%
Crude oil equivalent (per Boe)⁽³⁾	$	37.64	$	39.11	$	(1.47	)	(4	)%

_____________________________


(1)	Crude oil sales excludes $0.7 million and $0.1 million of oil transportation revenues from third parties, which do not have associated sales volumes, for the three months ended June 30, 2019 and 2018, respectively.


(2)	Natural gas sales excludes $0.9 million and $0.3 million of gas gathering revenues from third parties, which do not have associated sales volumes, for the three months ended June 30, 2019 and 2018, respectively.


(3)	Determined using the ratio of 6 Mcf of natural gas to 1 Bbl of crude oil.


(4)	Crude oil sales volumes includes 145.6 MBbls of sales volumes from the Mid-Continent region for the three months ended June 30, 2018. The Mid-Continent region assets were sold August 6, 2018, and therefore, no sales volumes were associated with the Mid-Continent region during the three months ended June 30, 2019.


(5)	Natural gas sales volumes includes 493.3 MMcf of sales volumes from the Mid-Continent region for the three months ended June 30, 2018. The Mid-Continent region assets were sold August 6, 2018, and therefore, no sales volumes were associated with the Mid-Continent region during the three months ended June 30, 2019.


(6)	Natural gas liquids sales volumes includes 40.1 MBbls of sales volumes from the Mid-Continent region for the three months ended June 30, 2018. The Mid-Continent region assets were sold August 6, 2018, and therefore, no sales volumes were associated with the Mid-Continent region during the three months ended June 30, 2019.

(7)

Derivatives economically hedge the price we receive for crude oil and natural gas. For the three months ended June 30, 2019, derivative cash settlement losses for oil contracts was approximately $1.0 million, and the derivative cash settlement gain for natural gas contracts was approximately $0.4 million. For the three months ended June 30, 2018, the derivative cash settlement loss for oil contracts was $7.3 million. Please refer to Note 10 - Derivatives of Part I, Item 1 of this report for additional disclosures.

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Product revenues increased for the three months ended June 30, 2019 by 18%, to $84.2 million, compared to $71.5 million for the three months ended June 30, 2018. The increase was primarily due to a 36% increase in oil equivalent sales volumes, partially offset by a 13% decrease in oil equivalent pricing excluding the impact of derivatives. The increase in sales volumes is due to turning 43 wells to sales during the twelve month period ending June 30, 2019.

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



	Three Months Ended June 30,
	2019		2018		Change			Percent Change
Expenses (in thousands):
Lease operating expense	$	6,390	$	11,316	$	(4,926	)	(44	)%
Gas plant and midstream operating expense		2,709		3,247		(538	)	(17	)%
Gathering, transportation, and processing		4,331		1,660		2,671		161	%
Severance and ad valorem taxes		7,711		6,071		1,640		27	%
Exploration		408		221		187		85	%
Depreciation, depletion, and amortization		18,898		9,564		9,334		98	%
Abandonment and impairment of unproved properties		878		2,477		(1,599	)	(65	)%
General and administrative		9,803		9,917		(114	)	(1	)%
Operating Expenses	$	51,128	$	44,473	$	6,655		15	%

Selected Costs ($ per Boe):
Lease operating expense	$	2.87	$	6.90	$	(4.03	)	(58	)%
Gas plant and midstream operating expense		1.22		1.98		(0.76	)	(38	)%
Gathering, transportation, and processing		1.95		1.01		0.94		93	%
Severance and ad valorem taxes		3.47		3.70		(0.23	)	(6	)%
Exploration		0.18		0.13		0.05		38	%
Depreciation, depletion, and amortization		8.50		5.83		2.67		46	%
Abandonment and impairment of unproved properties		0.39		1.51		(1.12	)	(74	)%
Unused commitments		—		—		—		—	%
General and administrative		4.41		6.05		(1.64	)	(27	)%
Operating Expenses	$	22.99	$	27.11	$	(4.12	)	(15	)%

Lease operating expense. Our lease operating expense (“LOE”) decreased $4.9 million, or 44%, to $6.4 million for the three months ended June 30, 2019 from $11.3 million for the three months ended June 30, 2018, and decreased on an equivalent basis per Boe by 58%. During the three months ended June 30, 2019, the Company experienced decreases, when compared to the same period in 2018, in well servicing and maintenance costs of $2.6 million, in equipment rental costs of $0.9 million, and in pumping and gauging costs of $0.6 million. These decreases are due to improved cost management and the sale of our Mid-Continent assets that were owned during the three months ended June 30, 2018 and sold on August 6, 2018. LOE per unit decreased on a higher percentage basis due to the higher production recorded in the quarter ended June 30, 2019 as compared to the quarter ended June 30, 2018.

Gas plant and midstream operating expense. Our gas plant and midstream operating expense decreased $0.5 million, or 17%, to $2.7 million for the three months ended June 30, 2019 from $3.2 million for the three months ended June 30, 2018, and decreased 38% on a per Boe basis during the comparable periods. Gas plant and midstream operating expense for the second quarter of 2018 is inclusive of $1.1 million in gas plant expense related to properties sold in the Mid-Continent sale on August 6, 2018.

Gathering, transportation, and processing. Gathering, transportation, and processing expense increased by $2.7 million to $4.3 million for the three months ended June 30, 2019, from $1.7 million for the three months ended June 30, 2018. The increase was primarily due to additional sales contracts becoming effective during the first quarter of 2019 in which natural gas production is sold at processing facilities' inlet meters as opposed to existing contracts where custody is transfered at the

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wellhead. Due to the point of custody transfer, the revenues and gathering, transportation, and processing expense to be shown on a gross, rather than net, basis. In addition to the new contracts, sales volumes increased 36% as compared to the three months ended June 30, 2018. Sales volumes have a direct correlation to gathering, transportation, and processing expense.

Severance and ad valorem taxes. Our severance and ad valorem taxes increased 27% to $7.7 million for the three months ended June 30, 2019 from $6.1 million for the three months ended June 30, 2018. Severance and ad valorem taxes primarily correlate to revenues. Revenues increased by 18% during the three months ended June 30, 2019.

Depreciation, depletion, and amortization. Our depreciation, depletion, and amortization expense increased 98% to $18.9 million for the three months ended June 30, 2019 from $9.6 million for the three months ended June 30, 2018, and increased 46% on a per boe basis. The increase in depreciation, depletion, and amortization during the three months ended June 30, 2019 when compared to the three months ended June 30, 2018 correlates to a $249.6 million increase in the depletable property base in conjunction with an increase in the depletion rate driven by a substantial increase in production.

Abandonment and impairment of unproved properties. The Company incurred $0.9 million and $2.5 million of abandonment and impairment of unproved properties costs during the three months ended June 30, 2019 and 2018, respectively. During the three months ended June 30, 2019, the Company incurred its standard annual amortization of $0.9 million on its emergence leases that were not held by production. During the three months ended June 30, 2018, the Company incurred impairment charges relating to non-core leases expiring and its standard annual amortization.

General and administrative. Our general and administrative expense decreased by $0.1 million for the three months ended June 30, 2019 from the three months ended June 30, 2018, and decreased by 27% on a per Boe basis between the comparable periods. General and administrative expense for the three months ended June 30, 2019 is comparable to the same period in 2018. General and administrative expense per Boe decreased on a higher percentage basis due to the higher production recorded in the quarter ended June 30, 2019 as compared to the quarter ended June 30, 2018.

Derivative gain (loss). Our derivative gain for the three months ended June 30, 2019 was $8.2 million as compared to a derivative loss of $22.0 million for the three months ended June 30, 2018. Our derivative gain is due to settlements and fair market value adjustments caused by market prices being lower than our contracted hedge prices. Please refer to Note 10 - Derivatives of Part I, Item 1 of this report for additional discussion.

Interest expense. Our interest expense for the three months ended June 30, 2019 and 2018 was $0.4 million and $0.8 million, respectively. The Company incurred $0.3 million in commitment fees on the available borrowing base under the Current Credit Facility, and $0.1 million due to the amortization of deferred financing costs during the three months ended June 30, 2019. The Company incurred $0.6 million in interest expense associated with the Prior Credit Facility and $0.2 million in commitment fees on the available borrowing base under the Prior Credit Facility during the three months ended June 30, 2018. Average debt outstanding for the three months ended June 30, 2019 and 2018 was $65.0 million and $45.6 million, respectively.

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



	Six Months Ended June 30,
	2019		2018		Change			Percent Change
Revenues (in thousands):
Crude oil sales⁽¹⁾	$	134,530	$	112,479	$	22,051		20	%
Natural gas sales⁽²⁾		12,402		10,563		1,839		17	%
Natural gas liquids sales ⁽³⁾		8,607		12,191		(3,584	)	(29	)%
Product revenue	$	155,539	$	135,233	$	20,306		15	%

Sales Volumes:
Crude oil (MBbls)⁽⁴⁾		2,582.0		1,847.8		734.2		40	%
Natural gas (MMcf)⁽⁵⁾		5,101.4		4,313.0		788.4		18	%
Natural gas liquids (MBbls)⁽⁶⁾		657.0		582.2		74.8		13	%
Crude oil equivalent (MBoe)⁽³⁾		4,089.2		3,148.8		940.4		30	%

Average Sales Prices (before derivatives)⁽⁷⁾:
Crude oil (per Bbl)	$	52.10	$	60.87	$	(8.77	)	(14	)%
Natural gas (per Mcf)	$	2.43	$	2.45	$	(0.02	)	(1	)%
Natural gas liquids (per Bbl)	$	13.10	$	20.94	$	(7.84	)	(37	)%
Crude oil equivalent (per Boe)⁽³⁾	$	38.04	$	42.95	$	(4.91	)	(11	)%

Average Sales Prices (after derivatives)⁽⁷⁾:
Crude oil (per Bbl)	$	52.53	$	54.47	$	(1.94	)	(4	)%
Natural gas (per Mcf)	$	2.29	$	2.50	$	(0.21	)	(8	)%
Natural gas liquids (per Bbl)	$	13.10	$	20.94	$	(7.84	)	(37	)%
Crude oil equivalent (per Boe)⁽³⁾	$	38.13	$	39.26	$	(1.13	)	(3	)%

_____________________________


(1)	Crude oil sales excludes $1.3 million and $0.2 million of oil transportation revenues from third parties, which do not have associated sales volumes, for the six months ended June 30, 2019 and 2018, respectively.


(2)	Natural gas sales excludes $1.5 million and $0.6 million of gas gathering revenues from third parties, which do not have associated sales volumes, for the six months ended June 30, 2019 and 2018, respectively.


(3)	Determined using the ratio of 6 Mcf of natural gas to 1 Bbl of crude oil.


(4)	Crude oil sales volumes includes 295.6 MBbls of sales volumes from the Mid-Continent region for the six months ended June 30, 2018. The Mid-Continent region assets were sold August 6, 2018, and therefore, no sales volumes were associated with the Mid-Continent region during the six months ended June 30, 2019.


(5)	Natural gas sales volumes includes 985.4 MMcf of sales volumes from the Mid-Continent region for the six months ended June 30, 2018. The Mid-Continent region assets were sold August 6, 2018, and therefore, no sales volumes were associated with the Mid-Continent region during the six months ended June 30, 2019.


(6)	Natural gas liquids sales volumes includes 80.4 MBbls of sales volumes from the Mid-Continent region for the six months ended June 30, 2018. The Mid-Continent region assets were sold August 6, 2018, and therefore, no sales volumes were associated with the Mid-Continent region during the six months ended June 30, 2019.

(7)

Derivatives economically hedge the price we receive for crude oil. For the six months ended June 30, 2019, derivative cash settlement gains for oil contracts was $1.1 million, and the derivative cash settlement loss for natural gas contracts was $0.7 million. For the six months ended June 30, 2018, the derivative cash settlement loss for oil contracts was $11.8 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 increased for the six months ended June 30, 2019 by 15%, to $155.5 million, compared to $135.2 million for the six months ended June 30, 2018. The increase was primarily due to a 30% increase in oil equivalent sales

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volumes, partially offset by a 11% decrease in oil equivalent pricing excluding the impact of derivatives. The increase in sales volumes is due to turning 43 wells to sales during the twelve month period ending June 30, 2019.

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



	Six Months Ended June 30,
	2019		2018		Change			Percent Change
Expenses (in thousands):
Lease operating expense	$	11,816	$	21,775	$	(9,959	)	(46	)%
Gas plant and midstream operating expense		5,030		6,860		(1,830	)	(27	)%
Gathering, transportation, and processing		8,353		3,998		4,355		109	%
Severance and ad valorem taxes		11,959		11,303		656		6	%
Exploration		505		250		255		102	%
Depreciation, depletion, and amortization		34,657		17,072		17,585		103	%
Abandonment and impairment of unproved properties		1,757		4,979		(3,222	)	(65	)%
Unused commitments		—		21		(21	)	(100	)%
General and administrative		20,081		19,451		630		3	%
Operating Expenses	$	94,158	$	85,709	$	8,449		10	%

Selected Costs ($ per Boe):
Lease operating expense	$	2.89	$	6.92	$	(4.03	)	(58	)%
Gas plant and midstream operating expense		1.23		2.18		(0.95	)	(44	)%
Gathering, transportation, and processing		2.04		1.27		0.77		61	%
Severance and ad valorem taxes		2.92		3.59		(0.67	)	(19	)%
Exploration		0.12		0.08		0.04		50	%
Depreciation, depletion, and amortization		8.48		5.42		3.06		56	%
Abandonment and impairment of unproved properties		0.43		1.58		(1.15	)	(73	)%
Unused commitments		—		0.01		(0.01	)	(100	)%
General and administrative		4.91		6.18		(1.27	)	(21	)%
Operating Expenses	$	23.02	$	27.23	$	(4.21	)	(15	)%

Lease operating expense. Our lease operating expense decreased $10.0 million, or 46%, to $11.8 million for the six months ended June 30, 2019 from $21.8 million for the six months ended June 30, 2018, and decreased on an equivalent basis per Boe by 58%. During the six months ended June 30, 2019, the Company experienced decreases, when compared to the same period in 2018, in well servicing and maintenance costs of $8.3 million and equipment rental costs of $1.8 million. These decreases are due to improved cost management and the sale of our Mid-Continent assets that were owned during the six months ended June 30, 2018 and sold on August 6, 2018. LOE per unit decreased on a higher percentage basis due to the higher production recorded in the quarter ended June 30, 2019 as compared to the quarter ended June 30, 2018.

Gas plant and midstream operating expense. Our gas plant and midstream operating expense decreased $1.8 million, or 27%, to $5.0 million for the six months ended June 30, 2019 from $6.9 million for the six months ended June 30, 2018, and decreased 44% on a per Boe basis during the comparable periods. Gas plant and midstream operating expense for the six months ended June 30, 2018 is inclusive of $2.3 million in gas plant expense related to properties sold in the Mid-Continent sale on August 6, 2018.

Gathering, transportation, and processing. Gathering, transportation, and processing expense increased by $4.4 million to $8.4 million for the six months ended June 30, 2019. from $4.0 million for the six months ended June 30, 2018. The increase was primarily due to additional sales contracts becoming effective during the first quarter of 2019 in which natural gas production is sold at processing facilities' inlet meters as opposed to existing contracts where custody is transfered at the wellhead. Due to the point of custody transfer, the revenues and gathering, transportation, and processing expense to be shown

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on a gross, rather than net, basis. In addition to the new contracts, sales volumes increased 30% as compared to the six months ended June 30, 2018. Sales volumes have a direct correlation to gathering, transportation, and processing expense.

Severance and ad valorem taxes. Our severance and ad valorem taxes increased 6% to $12.0 million for the six months ended June 30, 2019 from $11.3 million for the six months ended June 30, 2018. Severance and ad valorem taxes primarily correlate to revenues. Revenues increased by 15% during the three months ended June 30, 2019. The increase in severance and ad valorem taxes were offset by a refund that was received within the first quarter of 2019.

Depreciation, depletion, and amortization. Our depreciation, depletion, and amortization expense increased $17.6 million and increased 56% on a per Boe basis for the six months ended June 30, 2019 when compared to the same period in 2018. The increase in depreciation, depletion, and amortization during the six months ended June 30, 2019 when compared to the six months ended June 30, 2018 correlates to a $249.6 million increase in the depletable property base in conjunction with an increase in the depletion rate driven by a substantial increase in production.

Abandonment and impairment of unproved properties. The Company incurred $1.8 million and $5.0 million of abandonment and impairment of unproved properties costs during the six months ended June 30, 2019 and 2018, respectively. During the six months ended June 30, 2019, the Company incurred its standard annual amortization of $1.8 million on its emergence leases that were not held by production. During the six months ended June 30, 2018, the Company incurred impairment charges relating to non-core leases expiring and its standard annual amortization.

General and administrative. Our general and administrative expense increased by $0.6 million to $20.1 million for the six months ended June 30, 2019 from $19.5 million for the six months ended June 30, 2018, and decreased by 21% on a per Boe basis between the comparable periods. The increase in general and administrative expense between the comparable periods is primarily due to a severance payment made to the Company's Senior Vice President, Finance and Planning upon separation from the Company. General and administrative expense per Boe decreased on a higher percentage basis due to the higher production recorded in the quarter ended June 30, 2019 as compared to the quarter ended June 30, 2018.

Derivative loss. Our derivative loss for the six months ended June 30, 2019 was $28.4 million as compared to a derivative loss of $30.8 million for the six months ended June 30, 2018. Our derivative loss is due to settlements and fair market value adjustments caused by market prices being higher 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 six months ended June 30, 2019 and 2018 was $1.5 million and $1.2 million, respectively. The Company incurred $0.8 million in interest expense associated with its Current Credit Facility, $0.5 million in commitment fees on the available borrowing base under the Current Credit Facility, and $0.2 million due to the amortization of deferred financing costs during the six months ended June 30, 2019. The Company incurred $0.8 million in interest expense associated with the Prior Credit Facility and $0.4 million in commitment fees on the available borrowing base under the Prior Credit Facility during the six months ended June 30, 2018. Average debt outstanding for the six months ended June 30, 2019 and 2018 was $64.8 million and $28.1 million, respectively.

Liquidity and Capital Resources

The Company's anticipated sources of liquidity include cash from operating activities, borrowings under the Current 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 some of the pricing risk, we have approximately 55% of our 2019 guided production hedged as of June 30, 2019 and as of the filing date of this report, respectively.

As of June 30, 2019, our liquidity was $294.1 million, consisting of cash on hand of $9.1 million and $285.0 million of available borrowing capacity on the Current Credit Facility. Please refer to Note 5 - Long-term Debt in Part I, Item 1 above for additional discussion.

We anticipate investing approximately $230.0 million to $255.0 million, which will support drilling approximately 59 gross wells and turning to sales 45 gross wells in 2019.

Our weighted-average interest rates on borrowings from the Current Credit Facility was 4.6% for the three and six months ended June 30, 2019, respectively. As of June 30, 2019 and as of the date of filing, we had $65.0 million and $80.0 million, respectively, outstanding on our Current Credit Facility.

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



	Six Months Ended June 30,
	2019			2018
Net cash provided by operating activities	$	104,448		$	42,149
Net cash used in investing activities	(122,131		)	(93,037		)
Net cash provided by financing activities	13,917			60,174
Cash, cash equivalents, and restricted cash	9,236			22,068
Acquisition of oil and gas properties	(11,738		)	(1,295		)
Exploration and development of oil and gas properties	(111,398		)	(91,482		)

Cash flows provided by operating activities

The six months ended June 30, 2019 and 2018 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 $111.4 million and $91.5 million on the exploration and development of oil and gas properties during the six months ended June 30, 2019 and 2018, respectively. The increase in capital expenditures among the periods is primarily due to the timing of when wells were drilled and completed. The Company also spent $10.4 million more on acquisitions of oil and gas properties during the six months ended June 30, 2019 when compared to the same period in 2018.

Cash flows provided by financing activities

Net cash provided by financing activities for the six months ended June 30, 2019 and 2018 was $13.9 million and $60.2 million, respectively, primarily due to proceeds from our Current and Prior Credit Facility.

Non-GAAP Financial Measures

Adjusted EBITDAX represents earnings before interest, income taxes, depreciation, depletion, and amortization, exploration expense, and other non-cash and non-recurring charges. Adjusted EBITDAX excludes certain items that we believe affect the comparability of operating results and can exclude items that are generally non-recurring in nature or whose timing and/or amount cannot be reasonably estimated. Adjusted EBITDAX is a non-GAAP measure that we present because we believe it provides useful additional information to investors and analysts, as a performance measure, for analysis of our ability to internally generate funds for exploration, development, acquisitions, and to service debt. We are also subject to financial covenants under our Current 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 and may vary among companies, the adjusted EBITDAX amounts presented may not be comparable to similar metrics of other companies.

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):

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	Three Months Ended June 30,						Six Months Ended June 30,
	2019			2018			2019		2018
Net income	$	41,022		$	4,859		$	34,029	$	18,729
Exploration	408			221			505		250
Depreciation, depletion, and amortization	18,898			9,564			34,657		17,072
Amortization of deferred financing costs	123			—			248		—
Abandonment and impairment of unproved properties	878			2,477			1,757		4,979
Unused commitments	—			—			—		21
Stock-based compensation ⁽¹⁾	1,768			2,184			3,148		3,192
Severance costs⁽¹⁾	—			—			418		—
Loss on sale of oil and gas properties	1,432			—			306		—
Interest expense	385			805			1,536		1,162
Derivative loss (gain)	(8,173		)	22,012			28,371		30,754
Derivative cash settlements	(543		)	(7,310		)	393		(11,622		)
Income tax effect	—			—			—		—
Adjusted EBITDAX	$	56,198		$	34,812		$	105,368	$	64,537

⁽¹⁾Included as a portion of general and administrative expense in the accompanying statements of operations.

New Accounting Pronouncements

Please refer to Note 2 — Basis of Presentation under Part I, Item 1 of this report for any recently issued or adopted accounting standards.

Critical Accounting Policies and Estimates

Information regarding our critical accounting policies and estimates is contained in Part II, Item 7 of our 2018 Form 10-K.

Effects of Inflation and Pricing

Although the impact of inflation has been relatively insignificant in recent years, it is still a factor in the United States economy, and we tend to experience inflationary pressure on the cost of oilfield services and equipment as increasing oil and gas prices increase drilling activity in our areas of operations. Material changes in prices also impact the current revenue stream, estimates of future reserves, borrowing base calculations, depletion expense, impairment assessments of oil and gas properties, asset retirement obligation, and values of properties in purchase and sale transactions. Material changes in prices can impact the value of oil and gas companies and their ability to raise capital, borrow money, and retain personnel.

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 2018 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 effectiveness of vapor control systems at central tank batteries;


•	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 revenues and losses;


•	the timing and success of specific projects;


•	our implementation of standard and long reach laterals in the Wattenberg Field;


•	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 acreage, 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, 2018 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;


•	ability of our customers to meet their obligations to us;


•	our access to capital;


•	our ability to generate sufficient cash flow from operations, borrowings, or other sources to enable us to fully develop our undeveloped acreage positions;


•	the presence or recoverability of estimated oil and natural gas reserves and the actual future sales volume rates and associated costs;


•	uncertainties associated with estimates of proved oil and gas reserves;


•	the possibility that the industry may be subject to future local, state, and federal regulatory or legislative actions (including additional taxes and changes in environmental regulation);


•	environmental risks;


•	seasonal weather conditions;


•	lease stipulations;


•	drilling and operating risks, including the risks associated with the employment of horizontal drilling and completion techniques;


•	our ability to acquire adequate supplies of water for drilling and completion operations;


•	availability of oilfield equipment, services, and personnel;

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•	exploration and development risks;


•	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. Similarly, any improvements in oil and natural gas prices can have a favorable impact on our financial condition, results of operations, and capital resources.

Commodity Derivative Contracts

Our primary commodity risk management objective is to reduce volatility in our cash flows. We enter into derivative contracts for oil and natural gas using NYMEX futures or over-the-counter derivative financial instruments with only counterparties whom we believe are well-capitalized and have been approved by our Board of Directors. The types of derivative instruments that we have entered into include commodity price swaps and cashless collars to mitigate a portion of our exposure to fluctuations in commodity prices.

To the extent that we enter into derivative contracts, we may be prevented from realizing the full benefits of favorable price changes in the physical market. Likewise, depending on what type of derivative contracts we use, we may not be fully insulated from downward commodity price movements.

Presently, all of our derivative arrangements are concentrated with four counterparties, all of which are lenders under our Current Credit Facility. If these counterparties fail to perform their obligations, we may suffer financial loss.

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The result of oil market prices exceeding our swap prices or collar ceilings requires us to make payments on the settlement of our derivatives, if owed by us, generally up to 15 business days before we receive market price cash payments from our oil, natural gas, and NGL purchasers. This could have a material adverse effect on our cash flows for the period between derivative settlement and payment for revenues earned.

Please refer to the Note 10 - Derivatives in Part I, Item 1 of this report for summary derivative activity tables.

Interest Rates

As of June 30, 2019 and on the filing date of this report we had $65.0 million and $80.0 million, respectively, outstanding under our Current Credit Facility. Borrowings under our Current Credit Facility bear interest at a fluctuating rate that is tied to an adjusted Base Rate or London Interbank Offered Rate, at our option. Any increases in these interest rates can have an adverse impact on our results of operations and cash flow. As of June 30, 2019, and through the filing date of this report, the Company was in compliance with all financial and non-financial covenants in its Current 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. Five lenders under our Current Credit Facility are currently counterparties on our derivative instruments currently in place and have investment grade credit ratings.

We are also subject to credit risk due to concentration of our oil and natural gas receivables with certain significant customers. The inability or failure of our significant customers to meet their obligations to us or their insolvency or liquidation may adversely affect our financial results. We review the credit rating, payment history, and financial resources of our customers, but we do not require our customers to post collateral.

Marketability of Our Production

The marketability of our production depends in part upon the availability, proximity, and capacity of third-party refineries, access to regional trucking, pipeline and rail infrastructure, natural gas gathering systems, and processing facilities. We deliver crude oil and natural gas produced through trucking services and pipelines 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, adverse weather, 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 French Lake. 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, 2018.

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 June 30, 2019. 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 officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure. Based on the evaluation of our disclosure controls and procedures as of June 30, 2019, 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.

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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 June 30, 2019 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 are no material pending or overtly threatened legal actions against us of which we are aware.

On May 3, 2019, WEG filed a lawsuit against the Company and the other six operators who received the NOI, alleging claims consistent with those contained in the NOI letters. Because the allegations made in the lawsuit are based on novel and unprecedented interpretations of complex federal and state air quality laws and regulations, it is not possible for the Company to determine at this time whether the allegations have merit, but the Company will vigorously defend against such allegations, and will coordinate as much as possible with state and federal permitting authorities to maintain the validity of its current and future air permits for such facilities.

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, 2018.

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, 2018, and in Part I, Item 1A in our Quarterly Report on Form 10-Q for the three months ended March 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.

As a Colorado-only oil and gas operator, we face a disproportionate risk associated with increasing activism and legislative and regulatory efforts which may serve to curtail oil and gas exploration and development activities in Colorado.

Opposition toward oil and gas drilling and development activity in Colorado has both increased and become more effective in recent years. On April 16, 2019, new legislation became effective in Colorado, which substantially changes the state’s regulation of oil and gas exploration and production activities, and applies immediately to all pending permit applications. The new law changes the Colorado Oil and Gas Conservation Commission (“COGCC”) mission from “fostering” responsible and balanced development to “regulating” 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

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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, at least 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. Although the Company’s operations are not located near affected municipalities and may not ultimately be significantly impacted by select aspects of the new legislation and resulting COGCC rules, such permitting delays could substantially curtail the Company’s near-term pace of new oil and gas development.

Additionally, the new legislation requires the state’s Air Quality Control Commission (“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. 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.

The concentrated nature of our RMI system may increase the risk that we suffer lengthy interruptions in our production.

Through our Rocky Mountain Infrastructure, LLC (“RMI”) subsidiary, we have consolidated and interconnected our gathering, treating, and production facilities. This approach includes, for example, greater use of central processing facilities and central compression stations than some other operators in the Wattenberg Field. The concentrated nature of the RMI system, by itself, could increase the length and magnitude of a production interruption caused by operational problems located in otherwise localized portions of the system. Such interruptions could materially and adversely affect our ability to meet our public guidance, our financial condition, and our results of operations.

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 June 30, 2019.

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Issuer purchases of equity securities. The following table contains information about acquisitions of our equity securities during the three month period ended June 30, 2019:



					Maximum
				Total Number of	Number of
	Total			Shares	Shares that May
	Number of	Average Price		Purchased as Part of	Be Purchased
	Shares	Paid per		Publicly Announced	Under Plans or
	Purchased⁽¹⁾	Share		Plans or Programs	Programs
April 1, 2019 - April 30, 2019	31,565	$	23.41	—	—
May 1, 2019 - May 31, 2019	4,335	$	24.61	—	—
June 1, 2019 - June 30, 2019	245	$	19.14	—	—
Total	36,145	$	23.40	—	—

____________________________________________________________________________

(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 Current Credit Facility provides for restrictions on the payment of dividends.

Item 3. Defaults Upon Senior Securities.

None

Item 4. Mine Safety Disclosures.

Not applicable.

Item 5. Other Information.

The information set forth below is provided in accordance with and in satisfaction of the requirement of Item 1.01 “Entry into a Material Definitive Agreement” of Form 8-K.

On August 5, 2019, the Company adopted the Sixth Amended and Restated Executive Change in Control and Severance Plan (the “Severance Plan”), which amended provisions governing vesting of equity incentive awards in the event of termination of employment of a “Tier 5 Key Employee” by the Company without “Cause” or by a Tier 5 Key Employee for “Good Reason” not in connection with a “Change in Control” (each, as defined in the Severance Plan). The terms of the Severance Plan were amended such that for Tier 5 Key Employees, Pro-Rata Vesting of equity incentive awards shall control unless the equity incentive agreement applicable to the equity incentive award is more favorable to the Tier 5 Key Employee than the Pro-Rata Vesting, in which case such award agreement shall control. The Pro-Rata Vesting for Tier 5 Key Employees requires that a pro-rata portion of any restricted stock units that have not previously vested as of the Tier 5 Key Employee’s Date of Termination (as defined in the Severance Plan) shall vest as of such Date of Termination, with such pro rata portion equal to the product of (i) the number of such unvested restricted stock units and (ii) a fraction, the numerator of which is the number of days since the last scheduled vesting date that preceded the Tier 5 Key Employee’s Date of Termination during which the Tier 5 Key Employee remained an employee of the Company and the denominator of which is the total number of days between such last scheduled vesting date and the final vesting date of the vesting schedule.

The above description of the Severance Plan is not complete and is qualified in its entirety by reference to the full text of the Severance Plan, which is attached hereto as Exhibit 10.3 and incorporated herein by reference.

Item 6. Exhibits.

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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).


10.1†		Amended and Restated Form of PSU Award Agreement (incorporated by reference to Exhibit 10.1 to Bonanza Creek Energy, Inc.'s Form 10-Q filed on May 8, 2019).

10.2†		Letter Agreement dated June 20, 2017 between Bonanza Creek Energy, Inc. and Sandra Garbiso (incorporated by reference to Exhibit 10.1 to Bonanza Creek Energy, Inc.’s Form 8-K filed on June 20, 2019).

10.3†*		Form of Independent Director Restricted Stock Unit Agreement under the Bonanza Creek Energy, Inc. 2017 Long Term Incentive Plan.

10.4†*		Bonanza Creek Energy, Inc. Sixth Amended and Restated Executive Change in Control and Severance Plan.

16.1		Changes in Registrant’s Certifying Accountant (incorporated by reference to Exhibit 16.1 to Bonanza Creek Energy, Inc.’s Current Report on Form 8-K filed on June 19, 2019).

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

* 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:	August 7, 2019	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
			(principal accounting officer)



Name:		Name:
Social Security Number:		Social Security Number:
Address:		Address:
Date of Birth:		Date of Birth:
Relationship to Participant:		Relationship to Participant:
Percentage:		Percentage:



Name:		Name:
Social Security Number:		Social Security Number:
Address:		Address:
Date of Birth:		Date of Birth:
Relationship to Participant:		Relationship to Participant:
Percentage:		Percentage:


b)	"Designated Beneficiary" means the beneficiary or beneficiaries designated by Grantee in a writing filed with the Company in the form attached hereto as Exhibit A.


c)	"Disability" means that the Grantee is unable to engage in any substantial gainful activity by reason of any medically determinable physical or mental impairment that can be expected to result in death or can be expected to last for a continuous period of not less than 12 months.


d)	"Grantee" means the member of the Board specified in the grant notice issued by the Company on or about the Grant Date (the "Grant Notice").


e)	"Grant Date" means the date on which this Award was granted, as set forth in the Grant Notice.


f)	"Restricted Stock Units" means time-based Stock Units (as defined in the Plan) granted under this Agreement and subject to the terms of this Agreement and the Plan.


a)	Termination without Cause; Disability; Death. If Grantee’s Service on the Board terminates due to (i) removal from the Board without Cause or (ii) death or Disability, all unvested Restricted Stock Units shall vest in full upon such termination.


b)	Termination for Cause; Resignation. If Grantee’s Service on the Board terminates due to (i) removal from the Board for Cause or (ii) Grantee’s resignation from the Board, all unvested Restricted Stock Units shall be forfeited upon such termination.



	Bonanza Creek Energy, Inc. 2017 Long Term Incentive Plan Beneficiary Designation



Tier	Position
Tier 1	President and Chief Executive Officer
Tier 2	Executive Vice President
Tier 3	Senior Vice President
Tier 4	Vice President
Tier 5	Director, Senior Manager, Manager, and other key employee designated by the Administrator


a)	Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;


b)	Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;


c)	Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and


e)	e in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and


a)	All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and


b)	Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.


d)	Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and


5.	The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):