CIVITAS RESOURCES, INC. - Quarter Report: 2018 March (Form 10-Q)

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 March 31, 2018

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		(I.R.S. Employer
incorporation or organization)		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)

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. x 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). x 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 x

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 x 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. x Yes ¨ No

As of May 4, 2018, the registrant had 20,496,700 shares of common stock outstanding.

Table of Contents

BONANZA CREEK ENERGY, INC.

INDEX



			PAGE
Part I.	FINANCIAL INFORMATION

	Item 1.	Financial Statements (Unaudited)

		Condensed Consolidated Balance Sheets	3

		Condensed Consolidated Statements of Operations and Comprehensive Income (Loss)	4

		Condensed Consolidated Statements of Stockholders' Equity	5

		Condensed Consolidated Statements of Cash Flows	6

		Notes to the Condensed Consolidated Financial Statements	7

	Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	21

	Item 3.	Quantitative and Qualitative Disclosures About Market Risk	28

	Item 4.	Controls and Procedures	30

Part II.	OTHER INFORMATION

	Item 1.	Legal Proceedings	30

	Item 1A.	Risk Factors	31

	Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	31

	Item 3.	Defaults Upon Senior Securities	31

	Item 4.	Mine Safety Disclosures	31

	Item 5.	Other Information	31

	Item 6.	Exhibits	32

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 per share amounts)



	Successor
	March 31, 2018			December 31, 2017
ASSETS
Current assets:
Cash and cash equivalents	$	5,761		$	12,711
Accounts receivable:
Oil and gas sales	37,781			28,549
Joint interest and other	10,357			3,831
Prepaid expenses and other	3,153			6,555
Inventory of oilfield equipment	1,308			1,019
Derivative assets	126			488
Total current assets	58,486			53,153
Property and equipment (successful efforts method):
Proved properties	495,141			555,341
Less: accumulated depreciation, depletion and amortization	(21,401		)	(17,032		)
Total proved properties, net	473,740			538,309
Unproved properties	181,193			183,843
Wells in progress	68,735			47,224
Oil and gas properties held for sale, net of accumulated depreciation, depletion and amortization of $2,583 in 2018 (note 4)	82,504			—
Other property and equipment, net of accumulated depreciation of $2,482 in 2018 and $2,224 in 2017	4,551			4,706
Total property and equipment, net	810,723			774,082
Long-term derivative assets	56			6
Other noncurrent assets	3,142			3,130
Total assets	$	872,407		$	830,371
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable and accrued expenses (note 5)	$	69,148		$	62,129
Oil and gas revenue distribution payable	18,481			15,667
Derivative liability	15,427			11,423
Total current liabilities	103,056			89,219

Long-term liabilities:
Credit facility	15,000			—
Ad valorem taxes	15,435			11,584
Long-term derivative liability	3,086			2,972
Asset retirement obligations for oil and gas properties	26,939			38,262
Asset retirement obligations for oil and gas properties held for sale (note 4)	5,679			—
Total liabilities	169,195			142,037

Commitments and contingencies (note 7)

Stockholders’ equity:
Preferred stock, $.01 par value, 25,000,000 shares authorized, none outstanding	—			—
Common stock, $.01 par value, 225,000,000 shares authorized, 20,453,619 and 20,453,549 issued and outstanding in 2018 and 2017, respectively	4,286			4,286
Additional paid-in capital	690,076			689,068
Retained earnings (deficit)	8,850			(5,020		)
Total stockholders’ equity	703,212			688,334
Total liabilities and stockholders’ equity	$	872,407		$	830,371

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

Table of Contents

BONANZA CREEK ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME (LOSS) (UNAUDITED)

(in thousands, except per share amounts)



	Successor			Predecessor
	Three Months Ended March 31, 2018			Three Months Ended March 31, 2017

Operating net revenues:
Oil and gas sales	$	64,193		$	52,559
Operating expenses:
Lease operating expense	10,459			9,925
Gas plant and midstream operating expense	3,613			2,705
Gathering, transportation and processing	2,338			—
Severance and ad valorem taxes	5,233			4,319
Exploration	29			3,407
Depreciation, depletion and amortization	7,508			21,212
Abandonment and impairment of unproved properties	2,502			—
Unused commitments	21			993
General and administrative (including $1,008 and $1,725, respectively, of stock-based compensation)	9,533			12,094
Total operating expenses	41,236			54,655
Income (loss) from operations	22,957			(2,096		)
Other income (expense):
Derivative loss	(8,742		)	—
Interest expense	(357		)	(4,568		)
Reorganization items, net (note 2)	—			(89,003		)
Other income	12			1,391
Total other expense	(9,087		)	(92,180		)
Income (loss) from operations before taxes	13,870			(94,276		)
Income tax benefit (expense)	—			—
Net income (loss)	$	13,870		$	(94,276	)

Comprehensive income (loss)	$	13,870		$	(94,276	)

Basic net income (loss) per common share	$	0.68		$	(1.91	)

Diluted net income (loss) per common share	$	0.68		$	(1.91	)

Basic weighted-average common shares outstanding	20,454			49,452

Diluted weighted-average common shares outstanding	20,470			49,452

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

Table of Contents

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, 2017	20,453,549		$	4,286	$	689,068	$	(5,020	)	$	688,334
Restricted common stock issued	107			—		—		—			—
Restricted 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

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

Table of Contents

BONANZA CREEK ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(UNAUDITED)

(in thousands)



	Successor			Predecessor
	Three Months Ended March 31, 2018			Three Months Ended March 31, 2017

Cash flows from operating activities:
Net income (loss)	$	13,870		$	(94,276	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization	7,508			21,212
Non-cash reorganization items	—			57,341
Abandonment and impairment of unproved properties	2,502			—
Well abandonment costs and dry hole expense	—			2,701
Stock-based compensation	1,008			1,725
Derivative loss	8,742			—
Derivative cash settlements	(4,312		)	—
Other	172			383
Changes in current assets and liabilities:
Accounts receivable	(15,758		)	(3,814		)
Prepaid expenses and other assets	3,402			(536		)
Accounts payable and accrued liabilities	(566		)	31,092
Settlement of asset retirement obligations	(665		)	(176		)
Net cash provided by operating activities	15,903			15,652
Cash flows from investing activities:
Acquisition of oil and gas properties	(98		)	(439		)
Exploration and development of oil and gas properties	(37,664		)	(3,425		)
Proceeds from sale of oil and gas properties	20			—
Additions to property and equipment - non oil and gas	(103		)	(201		)
Net cash used in investing activities	(37,845		)	(4,065		)
Cash flows from financing activities:
Proceeds from credit facility	15,000			—
Payment of employee tax withholdings in exchange for the return of common stock	—			(335		)
Net cash provided by (used in) financing activities	15,000			(335		)
Net change in cash, cash equivalents and restricted cash	(6,942		)	11,252
Cash, cash equivalents and restricted cash:
Beginning of period	12,782			80,747
End of period	$	5,840		$	91,999
Supplemental cash flow disclosure:
Cash paid for interest	$	262		$	3,484
Changes in working capital related to drilling expenditures	$	14,250		$	4,404

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

Table of Contents

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, exploiting and producing oil and gas properties. The Company's assets and operations are concentrated primarily in the Wattenberg Field in Colorado and in the Dorcheat Macedonia Field in southern Arkansas.

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. As described below, however, prior financial statements are not comparable to our interim financial statements due to the adoption of fresh-start accounting.

The financial information as of December 31, 2017, has been derived from the audited financial statements contained in our Annual Report on Form 10-K for the year ended December 31, 2017 (“2017 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 2017 Form 10-K. The Company follows the same accounting principles for preparing quarterly and annual reports.

On January 4, 2017, the Company and certain of its subsidiaries (collectively with the Company, the “Debtors”) filed voluntary petitions (the “Bankruptcy Petitions,” and the cases commenced thereby, the “Chapter 11 Cases”) under Chapter 11 of the United States Bankruptcy Code (the “Bankruptcy Code”) in the United States Bankruptcy Court for the District of Delaware (the “Bankruptcy Court”) to pursue the Debtors’ Joint Prepackaged Plan of Reorganization Under Chapter 11 of the Bankruptcy Code (as proposed, the “Plan”). The Bankruptcy Court granted the Debtors' motion seeking to administer all of the Debtors' Chapter 11 Cases jointly under the caption In re Bonanza Creek Energy, Inc., et al (Case No. 17-10015). The Debtors received bankruptcy court confirmation of their Plan on April 7, 2017, and emerged from bankruptcy on April 28, 2017 (the “Effective Date”).

Upon emergence from bankruptcy, the Company adopted fresh-start accounting and became a new entity for financial reporting purposes. As a result of the application of fresh-start accounting and the effects of the implementation of the Plan, the Company’s condensed consolidated financial statements after April 28, 2017 are not comparable with the financial statements on or prior to April 28, 2017. The Company's condensed consolidated financial statements and related footnotes are presented with a black line division which delineates the lack of comparability between amounts presented after April 28, 2017 and dates prior thereto.

Subsequent to January 4, 2017 and through the date of emergence, all expenses, gains and losses directly associated with the reorganization are reported as reorganization items, net totaling $89.0 million in the accompanying condensed consolidated statements of operations and comprehensive income (loss) (“accompanying statements of operations”) for the three months ended March 31, 2017. The $89.0 million consists of a $51.2 million make-whole payment on the Senior Notes, $31.7 million in legal and professional fees and the write-off of $6.1 million of debt issuance and premium costs on the Senior Notes.

References to “Successor” or “Successor Company” relate to the financial position and results of operations of the reorganized Company subsequent to April 28, 2017. References to “Predecessor” or “Predecessor Company” relate to the financial position and results of operations of the Company on or prior to April 28, 2017.

Principles of Consolidation

The balance sheets include the accounts of the Company and its wholly owned subsidiaries, Bonanza Creek Energy Operating Company, LLC, Bonanza Creek Energy Resources, LLC, Bonanza Creek Energy Upstream LLC, Bonanza Creek Energy Midstream, LLC, Holmes Eastern Company, LLC and Rocky Mountain Infrastructure, LLC. All significant intercompany accounts and transactions have been eliminated.

Table of Contents

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, and 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.

Accounting Pronouncements Adopted in the Current Period

In May 2014, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Codification (“ASC”) Update No. 2014-09, Revenue from Contracts with Customers (Topic 606) (“ASC 606”) for the recognition of revenue from contracts with customers. Several additional related updates have been issued since that point. In summary, revenue recognition would occur upon the transfer of promised goods or services to customers in an amount that reflects the consideration to which the Company expects to be entitled in exchange for those goods or services. The guidance also requires enhanced financial statement disclosures over revenue recognition and provisions regarding future revenues and expenses under a gross-versus-net presentation.

The standard is required to be adopted using either the full retrospective approach, with all prior periods presented adjusted, or the modified retrospective approach, with a cumulative adjustment to retained earnings on the opening balance sheet. The standard is effective for annual reporting periods beginning after December 15, 2017, and interim periods within those annual periods. We adopted the new standard on January 1, 2018 and its adoption did not have a significant impact on our financial statements. Please refer to Note 3 - Revenue Recognition for additional discussion.

In January 2016, the FASB issued Update No. 2016-01 - Financial Instruments - Overall to require separate presentation of financial assets and financial liabilities by measurement category and form of financial asset on the balance sheet or the accompanying notes to the financial statements. This authoritative guidance is effective for fiscal years beginning after December 15, 2017 and interim periods within those fiscal years. We adopted the new standard on January 1, 2018 and its adoption did not have a material impact on our financial statements and disclosures.

In August 2016, the FASB issued Update No. 2016-15 - Classification of Certain Cash Receipts and Cash Payments, which clarifies the presentation of specific cash receipts and cash payments within the statement of cash flows. This authoritative accounting guidance is effective for annual periods, and interim periods within those annual periods, beginning after December 15, 2017. Early adoption is permitted. We adopted the new standard on January 1, 2018 and its adoption did not have a material impact on our statements of cash flows and related disclosures.

In November 2016, the FASB issued Update No. 2016-18, Statement of Cash Flows (Topic 230): Restricted Cash. This update clarifies how entities should present restricted cash and restricted cash equivalents in the statement of cash flows by including them with cash and cash equivalents when reconciling the total beginning and ending amounts for the periods shown on the statement of cash flows. This guidance is to be applied using a retrospective method and is effective for annual periods, and interim periods within those annual periods, beginning after December 15, 2017. Early adoption is permitted. We adopted the new standard on January 1, 2018 and the prior period has been adjusted to conform to the current period presentation, which resulted in an increase in cash used in investing activities of $0.1 million for the three months ended March 31, 2017.

The following table provides a reconciliation of cash, cash equivalents and restricted cash reported within the balance sheets that sums to the total of such amounts shown in the accompanying condensed consolidated statements of cash flows (in thousands):



	As of March 31, 2018		As of December 31, 2017
Cash and cash equivalents	$	5,761	$	12,711
Restricted cash included in other noncurrent assets	79		71
Total cash, cash equivalents and restricted cash as shown in the statements of cash flows	$	5,840	$	12,782

Restricted cash consists of funds for road maintenance and repairs.

In January 2017, the FASB issued Update No. 2017-01, Business Combinations (Topic 805): Clarifying the Definition of a Business. This update clarifies the definition of a business with the objective of adding guidance to assist entities with evaluating whether transactions should be accounted for as acquisitions (or disposals) of assets or businesses. This guidance is to be applied using a prospective method and is effective for annual periods, and interim periods within those annual periods,

Table of Contents

beginning after December 15, 2017. Early adoption is permitted. We adopted this new standard on January 1, 2018 and will apply it to any future acquisitions or disposals of assets or business.

In February 2017, the FASB issued Update No. 2017-05, Other Income-Gains and Losses from the Derecognition of Nonfinancial Assets (Subtopic 610-20): Clarifying the Scope of Asset Derecognition Guidance and Accounting for Partial Sales of Nonfinancial Assets. This update is meant to clarify existing guidance and to add guidance for partial sales of nonfinancial assets. This guidance is to be applied using a full retrospective method or a modified retrospective method as outlined in the guidance and is effective at the same time as Update 2014-09, Revenue from Contracts with Customers (Topic 606). We adopted this new standard on January 1, 2018 and its adoption did not have a material impact on our financial statements and disclosures.

In May 2017, the FASB issued Update No. 2017-09 (ASU 2017-09) Compensation - Stock Compensation (Topic 718). The purpose of this update is to provide clarity as to which modifications of awards require modification accounting under Topic 718, whereas previously issued guidance frequently resulted in varying interpretations and a diversity of practice. An entity should employ modification accounting unless the following are met: (1) the fair value of the award is the same immediately before and after the award is modified; (2) the vesting conditions are the same under both the modified award and the original award; and (3) the classification of the modified award is the same as the original award, either equity or liability. Regardless of whether modification accounting is utilized, award disclosure requirements under Topic 718 remain unchanged. This guidance will be effective for annual or any interim periods beginning after December 15, 2017. We adopted the new standard on the effective date of January 1, 2018 and its adoption did not have a material impact on our financial statements and disclosures.

Recently Issued Accounting Standards

In February 2016, the FASB issued Update No. 2016-02 – Leases to increase transparency and comparability among organizations by recognizing lease assets and lease liabilities on the balance sheet and disclosing key information about leasing arrangements. This authoritative guidance is effective for fiscal years beginning after December 15, 2018 and interim periods within those fiscal years. The Company has begun the identification process of all leases and is evaluating the provisions of this guidance and assessing its impact.

There are no other accounting standards applicable to the Company that would have a material effect on the Company's financial statements and disclosures that have been issued but not yet adopted by the Company as of March 31, 2018, and through the filing date of this report.

NOTE 3 - REVENUE RECOGNITION

On January 1, 2018, the Company adopted ASC 606, using the modified retrospective approach. Results for reporting periods beginning January 1, 2018, are presented in accordance with ASC 606, while prior period amounts are reported in accordance with ASC 605 - Revenue Recognition.

The impact of adoption on our current period results is as follows (in thousands):



	Three Months Ended March 31, 2018
	As Unadjusted⁽¹⁾		ASC 606 Adjustments		As Reported
Operating Revenues:
Oil sales	$	51,963	$	—	$	51,963
Natural gas sales		5,119		1,102		6,221
NGLs sales		4,773		1,236		6,009
Oil and gas sales		61,855		2,338		64,193
Operating expenses:
Gathering, transportation and processing		—		2,338		2,338
Total operating expenses		38,898		—		41,236
Net income	$	13,870	$	—	$	13,870

____________________

(1) This column excludes the impact of ASC 606 and is consistent with the presentation prior to January 1, 2018.

Table of Contents

Revenue from Contracts with Customers

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.

Performance Obligations

Oil sales

Under our oil sales contracts we sell oil production at the wellhead, or other contractually agreed-upon delivery point, 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.

Natural gas and NGLs Sales

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 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 consolidated 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.

Working interest partners

The Company and its working interest partners have entered into joint operating agreements which govern the marketing and selling of the working interest partner's share of oil, natural gas and NGLs interests. When selling oil, natural gas and NGLs on behalf of working interest owners, the Company is acting as an agent and thus reports the revenue on a net basis.

Transaction price

As noted above, the transaction price is generally tied to a market index, net of adjustments or price differentials, with the variable consideration being the estimation process and related accruals; however, any identified differences between our revenue estimates and actual revenue received historically have not been significant.

As further described in Note 7 - 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 March 31, 2018, 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.

Transaction price allocated to remaining performance obligations

Under our sales contracts, each unit of product represents a separate performance obligation; therefore, future volumes are wholly unsatisfied and the transaction price for remaining performance obligations is determined in accordance with the above section during the period in which the performance obligation is satisfied. For our product sales that have a contract term of one year or less, we applied the practical expedient under the guidance, which states that a Company is not required to disclose the transaction price allocated to remaining performance obligations if the performance obligation is part of a contract that has an original expected duration of one year or less.

Table of Contents

Contract balances

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 March 31, 2018 and December 31, 2017, our receivables from contracts with customers were $37.8 million and $28.5 million, respectively.

Prior-period performance obligations

We record revenue in the month production is delivered to the purchaser. However, settlement statements for certain natural gas and NGLs sales may not be received for 30 to 60 days after the date production is delivered, and as a result, we are required to estimate the amount of production delivered to the purchaser and the price that will be received for the sale of the product. We record the differences between our estimates and the actual amounts received for product sales in the month in which payment is received from the purchaser. We have existing internal controls for our revenue estimation process and related accruals, and any identified differences between our revenue estimates and actual revenue received historically have not been significant. For the period from January 1, 2018 through March 31, 2018, revenue recognized in the reporting period related to performance obligations satisfied in prior reporting periods was not material.

NOTE 4 - ASSETS HELD FOR SALE

During the first quarter of 2018, the Company established a plan to sell all of the Company's assets within its Mid-Continent region and North Park Basin, at which point they were deemed held for sale.

The Company sold its North Park Basin on March 9, 2018 for minimal net proceeds and full release of all current and future obligations resulting in a minimal net loss. As of December 31, 2017, the assets within the Company's North Park Basin represented $5.4 million, net of accumulated depreciation, depletion and amortization and a corresponding asset retirement obligation liability of approximately $5.4 million.

As of March 31, 2018, the Company had $82.5 million of oil and gas properties held for sale, net of $2.6 million accumulated depreciation, depletion and amortization as presented in the accompanying condensed consolidated balance sheets (“accompanying balance sheets”). These properties consist of all assets within the Company's Mid-Continent region. There is a corresponding asset retirement obligation liability of approximately $5.7 million in the asset retirement obligations for oil and gas properties held for sale in the accompanying balance sheets. There were no other assets or liabilities associated with the assets held for sale.

NOTE 5 - ACCOUNTS PAYABLE AND ACCRUED EXPENSES

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



	As of March 31, 2018		As of December 31, 2017
Drilling and completion costs	$	36,083	$	21,833
Accounts payable trade	5,240		6,256
Accrued general and administrative cost	2,922		10,025
Lease operating expense	3,927		5,005
Accrued interest	345		250
Accrued oil and gas hedging	1,561		808
Production and ad valorem taxes and other	19,070		17,952
Total accounts payable and accrued expenses	$	69,148	$	62,129

NOTE 6 - LONG-TERM DEBT

Long-term debt consisted of the following (in thousands):



	As of March 31, 2018		As of December 31, 2017
Credit facility	$	15,000	$	—
Total long-term debt	$	15,000	$	—

Table of Contents

Credit Facility

Upon emergence from bankruptcy, the Company entered into a new revolving credit facility, as the borrower, with KeyBank National Association, as the administrative agent, and certain lenders party thereto (the “credit facility”). The borrowing base of $191.7 million is redetermined semiannually, as early as April and October of each year, with the first redetermination set to occur in May 2018. The revolving credit facility matures on March 31, 2021.

The credit facility restricts, among other items, certain dividend payments, additional indebtedness, purchase of margin stock, asset sales, loans, investments and mergers. The credit facility also contains certain financial covenants, which require the maintenance of certain financial and leverage ratios, as defined by the credit facility. The credit facility states that the Company's leverage ratio of indebtedness to earnings before interest, income taxes, depreciation, depletion, and amortization, exploration expense and other non-cash charges (“EBITDAX”) is not to exceed 3.50 to 1.00. The Company must maintain a minimum current ratio of 1.00 to 1.00 and a minimum interest coverage ratio of trailing twelve-month EBITDAX to trailing twelve-month interest expense of 2.50 to 1.00 as of the end of the respective fiscal quarter. As of March 31, 2018, and through the filing date of this report, the Company was in compliance with all financial and non-financial covenants of the credit facility.

The credit facility provides for interest rates plus an applicable margin to be determined based on London Interbank Offered Rate (“LIBOR”) or a base rate, at the Company’s election. LIBOR borrowings bear interest at LIBOR, plus a margin of 3.00% to 4.00% depending on the utilization level, and the base rate borrowings bear interest at the “Reference Rate,” as defined in the credit facility, plus a margin of 2.00% to 3.00% depending on the utilization level.

NOTE 7 - 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 accounting authoritative guidance, an accrual is recorded for a loss contingency when its occurrence is probable and damages can be reasonably estimated based on the most likely anticipated outcome or the minimum amount within a range of possible outcomes. Because legal proceedings are inherently unpredictable and unfavorable resolutions could occur, assessing contingencies is highly subjective and requires judgments about uncertain future events. When evaluating contingencies, the Company may be unable to provide a meaningful estimate due to a number of factors, including the procedural status of the matter in question, the presence of complex or novel legal theories, and/or the ongoing discovery and development of information important to the matters. The Company regularly reviews contingencies to determine the adequacy of its accruals and related disclosures. No claims have been made, nor is the Company aware of any material uninsured liability which the Company may have, as it relates to any environmental cleanup, restoration or the violation of any rules or regulations. As of the filing date of this report, there were no material pending or overtly threatened legal actions against the Company of which it is aware.

As previously described in our 2017 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. Pursuant to the terms of the COC, the Company paid an administrative penalty of $0.2 million in 2017. The Company must also adopt procedures and processes to address the monitoring, reporting, and control of air emissions. The COC further sets forth compliance requirements and criteria for continued operations and contains provisions regarding record-keeping, modifications to the COC, circumstances under which the COC may terminate with respect to certain wells and facilities, and the sale or transfer of operational or ownership interests covered by the COC. In order to be in compliance, the Company incurred $0.7 million in 2017, and currently anticipates spending $3.5 million in 2018, and $3.1 million for 2019 through 2022. The COC can be terminated after four years with a showing of substantial compliance and CDPHE approval.

Commitments

The purchase agreement to deliver fixed determinable quantities of crude oil to NGL became effective on April 28, 2017. The terms of 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 volume commitments, which are set in six-month periods beginning in January 2018. There were no minimum volume commitments for the year ending December 31, 2017. During 2018, the average minimum volume commitment will be approximately 10,100 barrels per day, and the minimum volume commitment increases by approximately 41% from 2018 to

Table of Contents

2019 and approximately 3% each year thereafter for the remainder of the contract, to a maximum of approximately 16,000 barrels per day. The aggregate financial commitment fee over the remaining term, based on the minimum volume commitment schedule (as defined in the agreement) and the applicable differential fee, is $151.0 million as of March 31, 2018. 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.

On April 29, 2017, the Company entered into a new office lease agreement to rent office facilities. The lease is non-cancelable and expires in February 2022.

The annual minimum commitment payments under the NGL agreement and the office lease for the next five years as of March 31, 2018 are presented below (in thousands):



	NGL Commitments⁽¹⁾			Office Lease Commitments		Total
2018	$	12,172	$	751	$	12,923
2019		22,176		1,224		23,400
2020		27,949		1,335		29,284
2021		28,791		1,423		30,214
2022		29,485		240		29,725
2023 and thereafter		30,448		—		30,448
Total	$	151,021	$	4,973	$	155,994

_______________________________

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

There have been no other material changes from the commitments disclosed in the notes to the Company’s consolidated financial statements included in our 2017 Form 10-K.

NOTE 8 - STOCK-BASED COMPENSATION

2017 Long Term Incentive Plan

Upon emergence from bankruptcy, the Company adopted a new Long Term Incentive Plan (the “2017 LTIP”) and issued new grants to employees consisting of options with a ten-year term and strike price of $34.36 and restricted stock units (“RSUs”). These awards vest over a three-year period in equal installments on each anniversary of the grant date. See below for further discussion of awards under the 2017 LTIP.

Restricted Stock Units

The 2017 LTIP allows for the issuance of RSUs to members of the Board of Directors and employees of the Company at the discretion of the Board of Directors. Each RSU represents one share of the Company's common stock to be released from restriction upon completion of the vesting period. The awards typically vest in one-third increments over three years. The RSUs are valued at the grant date share price and are recognized as general and administrative expense over the vesting period of the award.

There were no RSUs granted during the three months ended March 31, 2018. Total expense recorded for RSUs, inclusive of grants to the members of the Board of Directors, for the three months ended March 31, 2018 was $0.7 million. As of March 31, 2018, unrecognized compensation cost was $6.3 million and will be amortized through 2020.

Table of Contents

A summary of the status and activity of non-vested restricted stock units for the three months ended March 31, 2018 is presented below:



	Restricted Stock Units		Weighted- Average Grant-Date Fair Value
Non-vested at beginning of year	261,165		$	34.93
Granted	—		$	—
Vested	(107	)	$	34.36
Forfeited	(2,138	)	$	34.36
Non-vested at end of quarter	258,920		$	34.93

Stock Options

The 2017 LTIP allows 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 are recognized as general and administrative expense over the vesting period of the award.

There were no stock options granted during the three months ended March 31, 2018. Total expense recorded for stock options for the three months ended March 31, 2018 was $0.3 million. As of March 31, 2018, unrecognized compensation cost was $2.4 million and will be amortized through 2020.

A summary of the status and activity of non-vested stock options for the three months ended March 31, 2018 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	197,271		$	34.36	9.3	$	—
Granted	—		—		—	$	—
Exercised	—		—		—	—
Forfeited	(2,138	)	34.36		9.3	$	—
Outstanding at end of quarter	195,133		$	34.36	8.6	$	—

A summary of additional information related to options outstanding and exercisable as of March 31, 2018 is presented below:



Exercise Price	Number of Options Outstanding and Exercisable	Weighted-Average Remaining Contractual Life (in days)
$34.36	107	69

NOTE 9 - 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. Observable inputs are inputs that market participants would use in pricing the asset or liability developed based on market data obtained from sources independent of the Company. Unobservable inputs are inputs that reflect the Company’s assumptions of what market participants would use in pricing the asset or liability developed based on the best information available in the circumstances. 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

Table of Contents

Level 2: Quoted prices in active markets for similar assets and liabilities, quoted prices for identical or similar instruments in markets that are not active, and model-derived valuations whose inputs are observable or whose significant value drivers are observable

Level 3: Significant inputs to the valuation model are unobservable

Financial and non-financial assets and liabilities are to be classified based on the lowest level of input that is significant to the fair value measurement. The Company’s assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of the fair value of assets and liabilities and their placement within the fair value hierarchy levels.

The following tables present the Company's financial and non-financial assets and liabilities that were accounted for at fair value as of March 31, 2018 and December 31, 2017 and their classification within the fair value hierarchy (in thousands):



	As of March 31, 2018
	Level 1		Level 2		Level 3
Derivative assets⁽¹⁾	$	—	$	182	$	—
Derivative liabilities⁽¹⁾	$	—	$	18,513	$	—
Unproved properties⁽²⁾	$	—	$	—	$	181,193



	As of December 31, 2017
	Level 1		Level 2		Level 3
Derivative assets⁽¹⁾	$	—	$	494	$	—
Derivative liabilities⁽¹⁾	$	—	$	14,395	$	—
Asset retirement obligations⁽³⁾	$	—	$	—	$	8,481

____________________________


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


(2)	Represents non-financial assets that are measured at fair value on a nonrecurring basis. Please refer to the Unproved Oil and Gas Properties sections below for additional discussion.


(3)	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.

Unproved Oil and Gas Properties

Unproved oil and gas property costs are evaluated for impairment and reduced to fair value when there is an indication that the carrying costs may not be fully recoverable. To measure the fair value of unproved properties, the Company uses Level 3 inputs and the income valuation technique, which takes into account the following significant assumptions: future development plans, risk weighted potential resource recovery, remaining lease life and estimated reserve values. The Company impaired non-core acreage in the Wattenberg Field due to leases expiring, which had a carrying value of $183.7 million to their fair value of $181.2 million, and recognized an impairment of unproved properties for the three months ended March 31, 2018 of $2.5 million.

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 and natural gas plants, 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 March 31, 2018. The Company had $8.5 million of asset retirement obligations recorded at fair value as of December 31, 2017.

Long-term Debt

The Company's credit facility approximates fair value as the applicable interest rates are floating. The outstanding balance under the credit facility as of March 31, 2018 was $15.0 million.

Table of Contents

NOTE 10 - 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%.

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



Beginning balance as of December 31, 2017	$	38,262
Liabilities settled		(665	)
Additions		44
Accretion expense		454
Sold properties		(5,477	)
Ending balance as of March 31, 2018⁽¹⁾	$	32,618

____________________________


(1)	Includes $5.7 million of asset retirement obligations associated with assets held for sale.

NOTE 11 - 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 and collar arrangements for oil and natural gas, and none of the derivative instruments qualify as having hedging relationships.

In a typical commodity swap agreement, if the agreed upon published third-party index price is lower than the swap 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.

Table of Contents

As of March 31, 2018, the Company had entered into the following commodity derivative contracts:



	Crude Oil (NYMEX WTI)		Natural Gas (NYMEX Henry Hub)
	Bbls/day	Weighted Avg. Price per Bbl	MMBtu/day	Weighted Avg. Price per MMBtu
Q218
Cashless Collar	2,000	$42.00/$52.50	5,600	$2.75/$3.43
Swap	3,500	$54.26	—	—
Q318
Cashless Collar	2,000	$43.00/$53.50	5,600	$2.75/$3.43
Swap	4,000	$56.65	—	—
Q418
Cashless Collar	2,000	$43.00/$53.50	5,600	$2.75/$3.43
Swap	4,000	$56.90	—	—
Q119
Cashless Collar	2,000	$43.00/$54.53	7,600	$2.75/$3.22
Swap	2,000	$56.32	—	—
Q219
Cashless Collar	1,330	$44.01/$54.79	2,505	$2.75/$3.22
Swap	2,500	$56.98	—	—
Q319
Swap	2,000	52.50	—	—
Q419
Swap	2,000	52.50	—	—

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



	Crude Oil (NYMEX WTI)		Natural Gas (NYMEX Henry Hub)
	Bbls/day	Weighted Avg. Price per Bbl	MMBtu/day	Weighted Avg. Price per MMBtu
Q218
Cashless Collar	2,000	$42.00/$52.50	6,259	$2.75/$3.38
Swap	3,835	$55.03	—	—
Q318
Cashless Collar	2,000	$43.00/$53.50	7,600	$2.75/$3.31
Swap	5,000	$57.87	—	—
Q418
Cashless Collar	2,000	$43.00/$53.50	6,600	$2.75/$3.37
Swap	5,000	$58.07	—	—
Q119
Cashless Collar	2,000	$43.00/$54.53	7,600	$2.75/$3.22
Swap	4,000	$58.16	—	—
Q219
Cashless Collar	1,330	$44.01/$54.79	2,505	$2.75/$3.22
Swap	4,500	$58.32	—	—
Q319
Swap	3,000	55.00	—	—
Q419
Swap	3,000	55.00	—	—

Table of Contents

Derivative Assets Fair Value

The Company’s commodity derivatives are measured at fair value and are included in the accompanying balance sheets as derivative assets and liabilities.

The following table contains a summary of all the Company’s derivative positions reported on the accompanying balance sheets as of March 31, 2018 and December 31, 2017 (in thousands):



		As of March 31, 2018			As of December 31, 2017
	Balance Sheet Location	Fair Value			Fair Value
Derivative Assets:
Commodity contracts	Current assets	$	126		$	488
Commodity contracts	Noncurrent assets	56			6
Derivative Liabilities:
Commodity contracts	Current liabilities	(15,427		)	(11,423		)
Commodity contracts	Long-term liabilities	(3,086		)	(2,972		)
Total derivative liabilities, net		$	(18,331	)	$	(13,901	)

The following tables summarizes the components of the derivative loss presented on the accompanying statements of operations for the periods below (in thousands):



	Successor			Predecessor
	Three Months Ended March 31, 2018			Three Months Ended March 31, 2017
Derivative cash settlement gain (loss):
Oil contracts	$	(4,506	)	$	—
Gas contracts	194			—
Total derivative cash settlement loss⁽¹⁾	$	(4,312	)	$	—

Change in fair value loss	(4,430		)	$	—

Total derivative loss⁽¹⁾	$	(8,742	)	$	—

_______________________________


(1)	Total derivative loss and total derivative cash settlement loss for the three months ended March 31, 2018 are reported in the derivative loss line item and derivative cash settlements line item in the accompanying condensed consolidated statements of cash flows, within cash flows from operating activities.

NOTE 12 - EARNINGS PER SHARE

The Company issued restricted stock units, which represent the right to receive, upon vesting, one share of the Company's common stock. 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 8 - Stock-Based Compensation for additional discussion.

The RSUs, stock options and warrants of the Company are all non-participating securities, and therefore, the Company used the treasury stock method to calculate earnings per share as shown in the following table (in thousands, except per share amounts):

Table of Contents



	Successor
	Three Months Ended March 31, 2018
Net income	$	13,870

Basic net income per common share	$	0.68

Diluted net income per common share	$	0.68

Weighted-average shares outstanding - basic	20,454
Add: dilutive effect of contingent stock awards	16
Weighted-average shares outstanding - diluted	20,470

There were 259,924 dilutive shares that were anti-dilutive for the three months ended March 31, 2018.

The Predecessor Company issued shares of restricted stock, which entitled the holders to receive non-forfeitable dividends, if and when the Predecessor Company was to declare a dividend, before vesting, thus making the awards participating securities. The awards are included in the calculation of earnings per share under the two-class method. The two-class method allocates earnings for the period between common shareholders and unvested participating shareholders and allocates losses to common shareholders only.

The Predecessor Company issued performance stock units (“PSUs”), which represented the right to receive, upon settlement of the PSUs, a number of shares of the Predecessor 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 measurement period applicable to such PSUs.

The Predecessor Company issued restricted stock, which are participating securities, and PSUs, and therefore, the Company used the two-class method to calculate earnings per share as shown in the following table (in thousands, except per share amounts):



	Predecessor
	Three Months Ended March 31, 2017
Net loss	$	(94,276	)
Less: undistributed loss to unvested restricted stock	—
Undistributed loss to common shareholders	(94,276		)
Basic net loss per common share	$	(1.91	)
Diluted net loss per common share	$	(1.91	)

Weighted-average shares outstanding - basic	49,452
Add: dilutive effect of contingent PSUs	—
Weighted-average shares outstanding - diluted	49,452

The Company was in a net loss position for the three months ended March 31, 2017, which made any potentially dilutive shares anti-dilutive. There were 278,414 dilutive shares that were anti-dilutive for the three months ended March 31, 2017. The participating shareholders are not contractually obligated to share in the losses of the Company, and therefore, the entire net loss is allocated to the outstanding common shareholders.

NOTE 13 - INCOME TAXES

On December 22, 2017, the U.S. Congress enacted 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. In accordance with U.S. GAAP, we recognized the effect of the rate change on deferred tax assets and liabilities as of December 31, 2017.

Table of Contents

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 March 31, 2018, 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 2018.

Table of Contents

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, 2017, 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 a Denver-based exploration and production company focused on the extraction of oil and associated liquids-rich natural gas in the United States. Our oil and liquids-weighted assets are concentrated primarily in the Wattenberg Field in Colorado and the Dorcheat Macedonia Field in southern Arkansas.

Chief Executive Officer Appointment

Effective April 11, 2018, the Company appointed Eric T. Greager as the new President and Chief Executive Officer of the Company. Mr. Greager has over 20 years of experience in the oil and gas industry, including exposure to both the operating and technical aspects of the industry.

Mr. Greager, 47, previously served as a Vice President and General Manager at Encana Oil & Gas (USA) Inc. Mr. Greager joined Encana in 2006, and served in various management and executive positions, including as a member of the boards of directors of Encana Procurement Inc. and Encana Oil & Gas (USA) Inc. Mr. Greager previously served on the board of directors of Western Energy Alliance and the board of managers of Hunter Ridge Energy Services. Mr. Greager received his Master’s Degree in Economics from the University of Oklahoma and his Bachelor’s Degree in Engineering from the Colorado School of Mines.

Bankruptcy Proceedings under Chapter 11

On January 4, 2017, the Company filed for Chapter 11 in the Bankruptcy Court. The Company received bankruptcy court confirmation of its Plan on April 7, 2017, and emerged from bankruptcy on April 28, 2017, the Effective Date.

Upon emergence from bankruptcy, the Company adopted fresh-start accounting and became a new entity for financial reporting purposes. Upon adoption of fresh-start accounting, our assets and liabilities were recorded at their fair values as of the Effective Date, which differed materially from the recorded values of those same assets and liabilities in the Predecessor Company. The lack of comparability between amounts presented after April 28, 2017 and dates prior thereto are presented with a black line division.

Outlook for 2018

The Company has started to accelerate its development program while testing enhanced completion designs on large-scale pads throughout the Company’s acreage position, including delineating its French Lake leasehold. The program contemplates running one rig in the first half of 2018 with a second rig added during the third quarter of 2018. The 2018 program is expected to grow Wattenberg annual production by approximately 20% in 2018 and greater than 50% in 2019, assuming a continuous two rig program. Allocated capital associated with this program is expected to be approximately $280.0 million to $320.0 million, which will support drilling 90 gross wells and turning online 55 gross wells in 2018.

Table of Contents

Results of Operations

Three Months Ended March 31, 2018 Compared to Three Months Ended March 31, 2017

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



		Successor		Predecessor
		Three Months Ended March 31, 2018		Three Months Ended March 31, 2017
Revenues:
Crude oil sales⁽¹⁾	$	51,839	$	39,933
Natural gas sales⁽²⁾		5,934		6,841
Natural gas liquids sales		6,009		5,785
Product revenue	$	63,782	$	52,559

Sales Volumes:
Crude oil (MBbls)		895.4		821.8
Natural gas (MMcf)		2,135.2		2,508.1
Natural gas liquids (MBbls)		257.6		340.2
Crude oil equivalent (MBoe)⁽³⁾		1,508.8		1,580.0

Average Sales Prices (before derivatives)⁽⁴⁾:
Crude oil (per Bbl)	$	57.89	$	48.59
Natural gas (per Mcf)	$	2.78	$	2.73
Natural gas liquids (per Bbl)	$	23.33	$	17.01
Crude oil equivalent (per Boe)⁽³⁾	$	42.27	$	33.26

Average Sales Prices (after derivatives)⁽⁴⁾:
Crude oil (per Bbl)	$	52.86	$	48.59
Natural gas (per Mcf)	$	2.87	$	2.73
Natural gas liquids (per Bbl)	$	23.33	$	17.01
Crude oil equivalent (per Boe)⁽³⁾	$	39.42	$	33.26

_____________________________


(1)	Crude oil sales excludes $0.1 million of oil transportation revenues from third parties, which do not have associated sales volumes, for both of the three months ended March 31, 2018 and 2017.


(2)	Natural gas sales excludes $0.3 million of gas gathering revenues from third parties, which do not have associated sales volumes, for both of the three months ended March 31, 2018 and 2017.


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


(4)	The derivatives economically hedge the price we receive for crude oil and natural gas. For the three months ended March 31, 2018, the derivative cash settlement loss for oil contracts was $4.5 million and the derivative cash settlement gain for natural gas contracts was $0.2 million. Please refer to Note 11 - Derivatives of Part I, Item 1 of this report for additional disclosures.

Operating revenues increased for the three months ended March 31, 2018 by 21%, to $63.8 million, compared to $52.6 million for the comparable period, due to a combination of a 27% increase in oil equivalent pricing, a 9% increase in oil sales volumes, partially offset by a 16% decrease in natural gas and NGLs sales volumes. The decreased volumes are a direct result of the Company suspending drilling and completion activities through the majority of 2016 and the first half of 2017, which caused a steady decline in production. In addition to the overall increase due to operations, there was an increase of $2.3 million related to the adoption of ASC 606, which caused certain revenues to be shown gross compared to a historical net presentation. Please refer to Note 3 - Revenue Recognition of Part I, Item 1 of this report for additional information.

Table of Contents

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



		Successor		Predecessor
		Three Months Ended March 31, 2018		Three Months Ended March 31, 2017
Expenses:
Lease operating expense	$	10,459	$	9,925
Gas plant and midstream operating expense		3,613		2,705
Gathering, transportation and processing		2,338		—
Severance and ad valorem taxes		5,233		4,319
Exploration		29		3,407
Depreciation, depletion and amortization		7,508		21,212
Abandonment and impairment of unproved properties		2,502		—
Unused commitments		21		993
General and administrative		9,533		12,094
Operating Expenses	$	41,236	$	54,655

Selected Costs ($ per Boe):
Lease operating expense	$	6.93	$	6.28
Gas plant and midstream operating expense		2.39		1.71
Gathering, transportation and processing		1.55		—
Severance and ad valorem taxes		3.47		2.73
Exploration		0.02		2.16
Depreciation, depletion and amortization		4.98		13.43
Abandonment and impairment of unproved properties		1.66		—
Unused commitments		0.01		0.63
General and administrative		6.32		7.65
Operating Expenses	$	27.33	$	34.59

Lease operating expense. Our lease operating expense increased $0.5 million, or 5%, to $10.5 million for the three months ended March 31, 2018 from $9.9 million for the comparable period in 2017 and increased on an equivalent basis per Boe by 10%. The Company experienced a $0.4 million increase in pumping and gauging charges during the three months ended March 31, 2018 when compared to the same period in 2017.

Gas plant and midstream operating expense. Our gas plant and midstream operating expense increased $0.9 million, or 34%, to $3.6 million for the three months ended March 31, 2018 from $2.7 million for the comparable period in 2017. Gas plant and midstream operating expense per Boe increased 40% during the comparable periods due to the costs associated with the accelerated schedule of compressor exchanges within our Rocky Mountain region.

Gathering, transportation and processing. As noted in the operating revenues section above, the increase to gathering, transportation and processing expense during the three months ended March 31, 2018 to $2.3 million is related to the Company's adoption of ASC 606, which caused certain revenues to be shown gross, with the related expenses recorded in this line item. Please refer to Note 3 - Revenue Recognition of Part I, Item 1 of this report for additional information.

Severance and ad valorem taxes. Our severance and ad valorem taxes increased 21% to $5.2 million for the three months ended March 31, 2018 from $4.3 million for the comparable period in 2017. Severance and ad valorem taxes primarily correlate to revenue. Revenues increased 21% over the comparable period.

Exploration. We incurred minimal exploration fees during the three months ended March 31, 2018. During the three months ended March 31, 2017, we expensed $0.7 million for seismic data within our Wattenberg Field and wrote-off $2.7 million for abandoned location costs within our Dorcheat Macedonia and Wattenberg Fields.

Table of Contents

Depreciation, depletion and amortization. Our depreciation, depletion and amortization expense per Boe was $4.98 and $13.43 for the three months ended March 31, 2018 and 2017, respectively. The three months ended March 31, 2018 reflects the $310.6 million fair value downward adjustment to the depletable asset base upon adoption of fresh-start accounting.

Abandonment and impairment of unproved properties. The Company incurred $2.5 million of impairment charges relating to non-core leases expiring within the Wattenberg Field during the three months ended March 31, 2018. There were no abandonment and impairment of unproved properties during the three months ended March 31, 2017.

Unused commitments. We incurred minimal unused commitment fees during the three months ended March 31, 2018. During the three months ended March 31, 2017 we incurred $1.0 million in unused commitment fees on our water purchase contract in the Wattenberg Field.

General and administrative. Our general and administrative expense decreased by $2.6 million to $9.5 million for the three months ended March 31, 2018 from $12.1 million for the comparable period in 2017. The decrease in general and administrative expense during the three months ended March 31, 2018 when compared to the same period in 2017 is due to a $1.6 million decrease in salaries and benefits and a $0.5 million decrease in bonuses due to workforce reductions.

Derivative loss. Our derivative loss for the three months ended March 31, 2018 was $8.7 million. We had no derivative contracts during the three months ended March 31, 2017. 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 11 - Derivatives of Part I, Item 1 of this report for additional discussion.

Interest expense. Our interest expense for the three months ended March 31, 2018 and 2017 was $0.4 million and $4.6 million, respectively. The interest expense associated with the revolving credit facilities was $0.1 million and $3.5 million for the three months ended March 31, 2018 and 2017, respectively. The Company incurred $0.3 million in commitment fees on the available borrowing base under the credit facility during the three months ended March 31, 2018. Interest expense and amortization of the debt premium and financing costs on the Senior Notes was $0.7 million and $0.4 million, respectively, for the three months ended March 31, 2017. Average debt outstanding for the three months ended March 31, 2018 and 2017 was $10.3 million and $991.7 million, respectively.

Reorganization items, net. Our reorganization expenses were $89.0 million for the three months ended March 31, 2017. Upon petition for Chapter 11, the Company incurred a $51.2 million make-whole payment on the Senior Notes, incurred $31.7 million in legal and professional fees and wrote-off $6.1 million of debt issuance and premium costs on the Senior Notes.

Liquidity and Capital Resources

The Company's anticipated sources of liquidity include cash from operating activities, borrowings under the credit facility, proceeds from sales of assets and potential proceeds from capital market transactions. Our cash flows from operating activities are subject to significant volatility due to changes in commodity prices for our crude oil, NGLs and natural gas products, 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 and other supply chain dynamics, among other factors. To mitigate some of the pricing risk, we have 37% and 43% of our 2018 guided production hedged as of March 31, 2018 and as of the filing date of this report, respectively.

As of March 31, 2018, our liquidity was $182.5 million, consisting of cash on hand of $5.8 million and $176.7 million of available borrowing capacity on the credit facility. Please refer to Note 6 - Long-term Debt in Part I, Item 1 above for additional discussion.

We anticipate investing approximately $280.0 million to $320.0 million, which will support drilling 90 gross wells and turning online 55 gross wells in 2018.

Our weighted-average interest rates on borrowings from the credit facility was 4.77% for the three months ended March 31, 2018.

Table of Contents

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



	Successor			Predecessor
	Three Months Ended March 31, 2018			Three Months Ended March 31, 2017
Net cash provided by operating activities	$	15,903		$	15,652
Net cash used in investing activities	(37,845		)	(4,065		)
Net cash provided by (used in) financing activities	15,000			(335		)
Cash, cash equivalents and restricted cash	5,840			$	91,999
Acquisition of oil and gas properties	98			439
Exploration and development of oil and gas properties	37,664			3,425

Cash flows provided by operating activities

The three months ended March 31, 2018 included cash receipts and disbursements attributable to our normal operating cycle. The three months ended March 31, 2017 contained reorganization costs along with our normal operating receipts and disbursements. 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 $37.7 million and $3.4 million on the exploration and development of oil and gas properties during the three months ended March 31, 2018 and 2017, respectively. The increase in capital expenditures between the comparable periods is a direct result of emerging from bankruptcy and resuming development operations.

Cash flows provided by (used in) financing activities

Net cash provided by financing activities for the three months ended March 31, 2018 is due to drawing $15.0 million on our credit facility. Net cash used in financing activities for the three months ended March 31, 2017 consisted of employee tax withholdings in exchange for the return of common stock.

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 2017 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, ARO, 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.

Contractual Obligations

Table of Contents

There have been no significant changes from our 2017 Form 10-K in our obligations and commitments. Please refer to Note 7 - Commitments and Contingencies under Part I, Item 1 of this report for additional discussion.

Cautionary Note Regarding Forward-Looking Statements

This Quarterly Report on Form 10-Q contains various statements, including those that express belief, expectation or intention, as well as those that are not statements of historic fact, that are forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities and Exchange Act of 1934, as amended (the “Exchange Act”). When used in this Quarterly Report on Form 10-Q, the words “could,” “believe,” “anticipate,” “intend,” “estimate,” “expect,” “may,” “continue,” “predict,” “potential,” “project,” “plan,” “will,” and similar expressions are intended to identify forward-looking statements, although not all forward-looking statements contain such identifying words. These forward-looking statements are based on management's current belief, based on currently available information, as to the outcome and timing of future events.

Forward‑looking statements include statements related to, among other things:


•	the Company's business strategies and intent to maximize liquidity;


•	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;


•	the Wattenberg Field being a premier oil and resource play in the United States;


•	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;


•	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;

Table of Contents


•	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 and C benches in our legacy acreage;


•	our ability to replace oil and natural gas reserves;


•	our ability to convert PUDs to producing properties within five years of their initial proved booking;


•	impact of recently issued accounting pronouncements;


•	impact of the loss a single customer or any purchaser of our products;


•	timing and ability to meet certain volume commitments related to purchase and transportation agreements;


•	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, 2017;


•	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;

Table of Contents


•	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 techniques;


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


•	availability of oilfield equipment, services and personnel;


•	exploration and development risks;


•	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 firm transportation for oil and natural gas we produce and to sell the oil and natural gas 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 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

Table of Contents

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 use of financial instruments may expose us to the risk of financial loss in certain circumstances, including instances when (1) sales volumes are less than expected requiring market purchases to meet commitments, or (2) our counterparties fail to purchase the contracted quantities of oil or otherwise fail to perform. To the extent that we engage in derivative contracts, we may be prevented from realizing the benefits of favorable price changes in the physical market. However, we are similarly insulated against decreases in such prices.

As of March 31, 2018, and through the filing date of this report, all of our derivative arrangements are concentrated with four counterparties, all of which are lenders under our credit facility. If these counterparties fail to perform their obligations, we may suffer financial loss or be prevented from realizing the benefits of favorable price changes in the physical market.

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

Interest Rates

As of March 31, 2018, we had $15.0 million outstanding drawn under our credit facility. Borrowings under our 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 March 31, 2018, and through the filing date of this report, the Company was in compliance with all financial and non-financial covenants.

Counterparty and Customer Credit Risk

In connection with our derivatives activity, we have exposure to financial institutions in the form of derivative transactions. Four lenders under our successor 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 from the Mid-Continent and Rocky Mountain regions 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 from these areas through trucking services, pipelines and rail facilities that we do not own. The lack of availability or capacity on these systems and facilities could reduce the price offered for our production or result in the shut-in of producing wells or the delay or discontinuance of development plans for properties.

Table of Contents

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, 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, 2017.

Item 4. Controls and Procedures.

Evaluation of Disclosure Controls and Procedures

Our management, with the participation of our principal executive officer and principal financial officer, evaluated the effectiveness of our disclosure controls and procedures as of March 31, 2018. 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 March 31, 2018, our principal executive officer and principal financial officer concluded that, as of such date, our disclosure controls and procedures were effective at the reasonable assurance level.

Management recognizes that any controls and procedures, no matter how well designed and operated, can provide only reasonable assurance of achieving their objectives and management necessarily applies its judgment in evaluating the cost-benefit relationship of possible controls and procedures. To assist management, we have established an internal audit function to verify and monitor our internal controls and procedures. The Company’s internal control system is supported by written policies and procedures, contains self-monitoring mechanisms and is audited by the internal audit function. Appropriate actions are taken by management to correct deficiencies as they are identified.

Changes in Internal Control over Financial Reporting

There were no changes in our internal control over financial reporting identified in management’s evaluation pursuant to Rules 13a-15(d) or 15d-15(d) of the Exchange Act during the quarter ended March 31, 2018 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.

As previously described in our 2017 Form 10-K, the Company and the CDPHE agreed to a 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. Pursuant to the terms of the COC, the Company paid an administrative penalty of $0.2 million in 2017. The Company must also adopt procedures and processes to address the monitoring, reporting, and control of air emissions. The COC further sets forth compliance requirements and criteria for continued operations and contains provisions regarding record-keeping, modifications to the COC, circumstances under which the COC may terminate with respect to certain wells and facilities, and the sale or transfer of operational or ownership interests covered by the COC. In order to be in compliance, the Company incurred $0.7 million in 2017, and currently anticipates spending $3.5 million in 2018, and $3.1 million for 2019 through 2022. The COC can be terminated after four years with a showing of substantial compliance and CDPHE approval.

Table of Contents

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, 2017.

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, 2017, 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.

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

Unregistered sales of securities. There were no sales of unregistered equity securities during the three month period ended March 31, 2018.

Issuer purchases of equity securities. The following table contains information about acquisitions of our equity securities during the three month period ended March 31, 2018:



					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
January 1, 2018 - January 31, 2018	—	$	—	—	—
February 1, 2018 - February 28, 2018	—	$	—	—	—
March 1, 2018 - March 31, 2018	37	$	27.89	—	—
Total	37	$	27.89	—	—

____________________________________________________________________________

(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 new revolving 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.

None.

Table of Contents

Item 6. Exhibits.



Exhibit No.		Description of Exhibit
10.1†		Bonanza Creek Energy, Inc. Fifth Amended and Restated Executive Change in Control and Severance Plan

10.2		Employment Agreement between the Company and Eric T. Greager, dated March 30, 2018 (incorporated by reference to Exhibit 10.1 to the Company's Current Report on Form 8-K filed on April 5, 2018).

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).

† Filed or furnished herewith

Table of Contents

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.



		BONANZA CREEK ENERGY, INC.

Date:	May 8, 2018	By:	/s/ Eric T. Greager
			Eric T. Greager
			President and Chief Executive Officer
			(principal executive officer)


		By:	/s/ Scott A. Fenoglio
			Scott A. Fenoglio
			Senior Vice President, Finance & Planning
			(principal financial officer)


		By:	/s/ Sandi K. Garbiso
			Sandi K. Garbiso
			Vice President and Chief Accounting Officer
			(principal accounting officer)