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, 2019
  Commission File Number:  001-35371
  Bonanza Creek Energy, Inc.
(Exact name of registrant as specified in its charter)  
Delaware
 
61-1630631
(State or other jurisdiction of incorporation or organization)
 
(I.R.S. Employer Identification No.)
410 17 th  Street, Suite 1400
 
 
Denver, Colorado
 
80202
(Address of principal executive offices)
 
(Zip Code)
(720) 440-6100
(Registrant’s telephone number, including area code)
Securities registered pursuant to Section 12(b) of the Act:
Title of each class
Trading Symbol
Name of exchange on which registered
Common Stock, par value $0.01 per share
BCEI
New York Stock Exchange
Securities registered pursuant to Section 12(g) of the Act: None.
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 x
 
Accelerated filer ¨
 
 
 
                                 Non-accelerated filer ¨ (Do not check if a smaller reporting company)
 
 
 
Emerging growth company ¨
 
Smaller reporting company ¨
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ¨
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).  ¨  Yes 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 6, 2019 , the registrant had 20,624,454 shares of common stock outstanding.
 

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Table of Contents

BONANZA CREEK ENERGY, INC.
INDEX
 
 
    
    
PAGE
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 


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Table of Contents

PART I - FINANCIAL INFORMATION

Item 1.     Financial Statements.
BONANZA CREEK ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS (UNAUDITED)
(in thousands, except share amounts)
 
March 31, 2019
 
December 31, 2018
ASSETS
 

 
 

Current assets:
 

 
 

Cash and cash equivalents
$
32,695

 
$
12,916

Accounts receivable:
 

 
 

Oil and gas sales
47,281

 
31,799

Joint interest and other
25,858

 
47,577

Prepaid expenses and other
5,073

 
4,633

Inventory of oilfield equipment
2,484

 
3,478

Derivative assets
6,400

 
34,408

Total current assets
119,791

 
134,811

Property and equipment ( successful efforts method):
 

 
 

Proved properties
782,323

 
719,198

Less: accumulated depreciation, depletion and amortization
(67,886
)
 
(52,842
)
Total proved properties, net
714,437

 
666,356

Unproved properties
154,599

 
154,352

Wells in progress
73,993

 
93,617

Other property and equipment, net of accumulated depreciation of $2,701 in 2019 and $2,546 in 2018
3,570

 
3,649

Total property and equipment, net
946,599

 
917,974

Long-term derivative assets
—

 
3,864

Right-of-use assets (note 3)
31,999

 
—

Other noncurrent assets
4,998

 
4,885

Total assets
$
1,103,387

 
$
1,061,534

LIABILITIES AND STOCKHOLDERS’ EQUITY
 

 
 

Current liabilities:
 

 
 

Accounts payable and accrued expenses (note 4)
$
56,021

 
$
79,390

Oil and gas revenue distribution payable
31,314

 
19,903

Current portion of right-of-use liability (note 3)
8,429

 
—

Derivative liability
4,889

 
183

Total current liabilities
100,653

 
99,476

 
 
 
 
Long-term liabilities:
 

 
 

Credit facility (note 5)
65,000

 
50,000

Right-of-use liability (note 3)
24,359

 
—

Ad valorem taxes
25,850

 
18,740

Asset retirement obligations for oil and gas properties
29,378

 
29,405

Total liabilities
245,240

 
197,621

 
 
 
 
Commitments and contingencies (note 6)


 


 
 
 
 
Stockholders’ equity:
 

 
 

Preferred stock, $.01 par value, 25,000,000 shares authorized, none outstanding
—

 
—

Common stock, $.01 par value, 225,000,000 shares authorized, 20,558,591 and 20,543,940 issued and outstanding as of March 31, 2019 and December 31, 2018, respectively
4,286

 
4,286

Additional paid-in capital
697,688

 
696,461

Retained earnings
156,173

 
163,166

Total stockholders’ equity
858,147

 
863,913

Total liabilities and stockholders’ equity
$
1,103,387

 
$
1,061,534

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

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BONANZA CREEK ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME (LOSS) (UNAUDITED)
(in thousands, except per share amounts)
 
 
Three Months Ended March 31,
 
2019
 
2018
Operating net revenues:
 

 
 
Oil and gas sales
$
72,594

 
$
64,193

Operating expenses:
 

 
 
Lease operating expense
5,426

 
10,459

Gas plant and midstream operating expense
2,321

 
3,613

Gathering, transportation, and processing
4,022

 
2,338

Severance and ad valorem taxes
4,248

 
5,233

Exploration
97

 
29

Depreciation, depletion, and amortization
15,759

 
7,508

Abandonment and impairment of unproved properties
879

 
2,502

Unused commitments
—

 
21

General and administrative expense (including $1,380 and $1,008, respectively, of stock-based compensation)
10,278

 
9,533

Total operating expenses
43,030

 
41,236

Income from operations
29,564

 
22,957

Other income (expense):
 

 
 
Derivative loss
(36,544
)
 
(8,742
)
Interest expense
(1,151
)
 
(357
)
Gain on sale of properties
1,126

 
—

Other income
12

 
12

Total other expense
(36,557
)
 
(9,087
)
Income (loss) from operations before taxes
(6,993
)
 
13,870

Income tax benefit (expense)
—

 
—

Net income (loss)
$
(6,993
)
 
$
13,870

 
 
 
 
Comprehensive income (loss)
$
(6,993
)
 
$
13,870

 
 
 
 
Basic net income (loss) per common share
$
(0.34
)
 
$
0.68

 
 
 
 
Diluted net income (loss) per common share
$
(0.34
)
 
$
0.68




 
 
Basic weighted-average common shares outstanding
20,557

 
20,454




 
 
Diluted weighted-average common shares outstanding
20,557

 
20,470

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






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BONANZA CREEK ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY (UNAUDITED)
(in thousands, except share amounts)
 
 
 
 
 
 
 
Additional
 
Retained
 
 
 
 
 
Common Stock
 
Paid-In
 
Earnings
 
 
 
 
    
Shares
    
Amount
    
Capital
    
(Deficit)
    
Total
Balances, December 31, 2018
 
20,543,940

 
$
4,286

 
$
696,461

 
$
163,166

 
$
863,913

Restricted common stock issued
 
20,687

 
 
—

 
 
—

 
 
—

 
 
—

Restricted stock used for tax withholdings
 
(6,036
)
 
 
—

 
 
(153
)
 
 
—

 
 
(153
)
Stock-based compensation
 
—

 
 
—

 
 
1,380

 
 
—

 
 
1,380

Net loss
 
—

 
 
—

 
 
—

 
 
(6,993
)
 
 
(6,993
)
Balances, March 31, 2019
 
20,558,591

 
$
4,286

 
$
697,688

 
$
156,173

 
$
858,147

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.



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Table of Contents

BONANZA CREEK ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(UNAUDITED)
(in thousands)
 
Three Months Ended March 31,
 
2019
 
2018
Cash flows from operating activities:
 

 
 
Net income (loss)
$
(6,993
)
 
$
13,870

Adjustments to reconcile net income (loss) to net cash provided by operating activities:
 
 
 
Depreciation, depletion, and amortization
15,759

 
7,508

Abandonment and impairment of unproved properties
879

 
2,502

Well abandonment costs and dry hole expense
62

 
—

Stock-based compensation
1,380

 
1,008

Amortization of deferred financing costs
125

 
—

Derivative loss
36,544

 
8,742

Derivative cash settlements
936

 
(4,312
)
Gain on sale of oil and gas properties
(1,126
)
 
—

Other
(900
)
 
172

Changes in current assets and liabilities:
 
 
 
Accounts receivable
6,237

 
(15,758
)
Prepaid expenses and other assets
(440
)
 
3,402

Accounts payable and accrued liabilities
(10,150
)
 
(566
)
Settlement of asset retirement obligations
(592
)
 
(665
)
Net cash provided by operating activities
41,721

 
15,903

Cash flows from investing activities:
 

 
 
Acquisition of oil and gas properties
(1,362
)
 
(98
)
Exploration and development of oil and gas properties
(36,503
)
 
(37,664
)
Proceeds from sale of oil and gas properties
1,153

 
20

Additions to property and equipment - non oil and gas
(76
)
 
(103
)
Net cash used in investing activities
(36,788
)
 
(37,845
)
Cash flows from financing activities:
 

 
 
Proceeds from Current Credit Facility
15,000

 
—

Proceeds from Prior Credit Facility
—

 
15,000

Payment of employee tax withholdings in exchange for the return of common stock
(153
)
 
—

Net cash provided by financing activities
14,847

 
15,000

Net change in cash, cash equivalents, and restricted cash
19,780

 
(6,942
)
Cash, cash equivalents, and restricted cash:
 

 
 
Beginning of period
13,002

 
12,782

End of period
$
32,782

 
$
5,840

Supplemental cash flow disclosure:
 

 
 
Cash paid for interest
$
661

 
$
262

Changes in working capital related to drilling expenditures
$
(5,710
)
 
$
14,250

     Cash paid for amounts included in the measurement of lease liabilities
$
2,032

 
$
—

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

6

BONANZA CREEK ENERGY, INC. AND SUBSIDIARIES
NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)

NOTE 1 - ORGANIZATION AND BUSINESS
Bonanza Creek Energy, Inc. (“BCEI” or, together with our consolidated subsidiaries, the “Company”) is engaged primarily in acquiring, developing, extracting, and producing oil and gas properties. The Company’s assets and operations are concentrated in the rural portions of the Wattenberg Field in Colorado.
NOTE 2 - BASIS OF PRESENTATION
These unaudited condensed consolidated financial statements have been prepared in accordance with U.S. generally accepted accounting principles (“GAAP”) for interim financial statements and pursuant to the rules and regulations of the Securities and Exchange Commission. In the opinion of management, the accompanying unaudited condensed consolidated financial statements reflect all adjustments consisting of normal recurring adjustments as necessary for a fair presentation of our financial position and results of operations. Interim results of operations are not necessarily indicative of the results to be expected for the full fiscal year.
The financial information as of December 31, 2018, has been derived from the audited financial statements contained in our Annual Report on Form 10-K for the year ended December 31, 2018 (“2018 Form 10-K”), but does not include all disclosures, including notes required by GAAP. As such, this quarterly report should be read in conjunction with the consolidated financial statements and related notes included in our 2018 Form 10-K. The Company follows the same accounting principles for preparing quarterly and annual reports.
Principles of Consolidation
      The balance sheets include the accounts of the Company and its wholly owned subsidiaries, Bonanza Creek Energy Operating Company, LLC, Holmes Eastern Company, LLC, and Rocky Mountain Infrastructure, LLC. All significant intercompany accounts and transactions have been eliminated.
Use of Estimates
The preparation of the Company's condensed consolidated financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of oil and gas reserves, assets and liabilities, disclosure of contingent assets and liabilities at the date of the balance sheet, and the reported amounts of revenue and expenses during the reporting period. Actual results could differ from those estimates.
Revenue Recognition
Sales of oil, natural gas, and natural gas liquids (“NGLs”) are recognized when performance obligations are satisfied at the point control of the product is transferred to the customer. Virtually all of our contracts’ pricing provisions are tied to a market index, with certain adjustments based on, among other factors, whether a well delivers to a gathering or transmission line, quality of the oil or natural gas, and prevailing supply and demand conditions. As a result, the price of the oil, natural gas, and NGLs fluctuates to remain competitive with other available oil, natural gas, and NGLs supplies.
As further described in Note 6 - Commitments and Contingencies , one contract with NGL Crude Logistics, LLP (“NGL”, known as the “NGL agreement”) has an additional aspect of variable consideration related to the minimum volume commitments (“MVCs”) as specified in the agreement. On an on-going basis, the Company performs an analysis of expected risk adjusted production applicable to the NGL agreement based on approved production plans to determine if liquidated damages to NGL are probable. As of March 31, 2019, the Company believes that the volumes delivered to NGL will be in excess of the MVCs required then and for the upcoming approved production plan. As a result of this analysis, to date, no variable consideration related to potential liquidated damages has been considered in the transaction price for the NGL agreement.
Under our oil sales contracts we sell oil production at the wellhead, or other contractually agreed-upon delivery points, and collect an agreed-upon index price, net of pricing differentials. In this scenario, we recognize revenue when control transfers to the purchaser at the wellhead, or other contractually agreed-upon delivery point, at the net contracted price received.
Under our natural gas processing contracts, we deliver natural gas to an agreed-upon delivery point. The delivery points are specified within each contract, and the transfer of control varies between the inlet and outlet of the midstream

7

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 accompanying condensed consolidated statements of operations (“statements of operations”). Alternatively, for those contracts where the Company relinquishes control at the inlet of the midstream processing facility, the Company recognizes natural gas and NGLs revenues based on the contracted amount of the proceeds received from the midstream processing entity and, as a result, we recognize revenue on a net basis.    
Under our product sales contracts, we invoice customers once our performance obligations have been satisfied, at which point payment is unconditional. Accordingly, our product sales contracts do not give rise to contract assets or liabilities under this guidance. At March 31, 2019 and December 31, 2018, our receivables from contracts with customers were $47.3 million and $31.8 million , respectively.
Revenue attributable to each of our identified revenue streams is disaggregated below (in thousands):
 
Three Months Ended March 31,
 
2019
 
2018
Operating Revenues:
 
 
 
   Oil sales
$
60,790

 
$
51,963

   Natural gas sales
7,456

 
6,221

   NGL sales
4,348

 
6,009

Oil and gas sales
$
72,594

 
$
64,193

Restricted Cash
The following table provides a reconciliation of cash, cash equivalents, and restricted cash reported within the balance sheets, which sum to the total of such amounts shown in the accompanying condensed consolidated statements of cash flows (“statements of cash flows”) (in thousands):
 
As of March 31,
 
2019
 
2018
Cash and cash equivalents
$
32,695

 
$
5,761

Restricted cash included in other noncurrent assets
87

 
79

Total cash, cash equivalents, and restricted cash as shown in the statements of cash flows
$
32,782

 
$
5,840

Restricted cash consists of funds for road maintenance and repairs.
Accounting Pronouncements Recently Adopted and Issued
In February 2016, the FASB issued Update No. 2016-02 - Leases (ASC 842) to increase transparency and comparability among organizations by recognizing right-of-use assets and liabilities on the balance sheet and disclosing key information about leasing arrangements. Each lease that is recognized in the balance sheet will be classified as either finance or operating requiring certain quantitative and qualitative disclosures. Leases acquired to explore the development of oil and natural gas resources are not within the scope of this guidance. The new standard was adopted using optional transition approach at the date of initial application on January 1, 2019. Please refer to Note 3 - Leases for additional disclosure.
In August 2018, the FASB issued Update No. 2018-13, Disclosure Framework-Changes to the Disclosure Requirements for Fair Value Measurement . The objective of this update is to improve the effectiveness of fair value measurement disclosures. This update is effective for annual periods beginning after December 15, 2019, and interim periods within those annual periods. The standard will only impact the Company's disclosures.
There are no other accounting standards applicable to the Company that would have a material effect on the Company’s financial statements and disclosures that have been issued but not yet adopted by the Company as of March 31, 2019, and through the filing date of this report.
NOTE 3 - LEASES
On January 1, 2019, the Company adopted ASC 842 using the optional transition approach prescribed in Updated No 2018-11 - Lease (Topic 842), Targeted Improvements . Under this approach, results for reporting periods beginning January 1,

8

2019, are presented in accordance with ASC 842, while prior period amounts are reported in accordance with ASC 840 - Leases . The Company recognized $32.8 million and $33.6 million in right-of-use assets and liabilities, respectively, on January 1, 2019, representing minimum payment obligations associated with compressors, vehicles, office space, and other field and corporate equipment with contractual durations in excess of one year. There was no cumulative-effect adjustment to retained earnings upon adoption of the new standard.
ASC 842 provided certain practical expedients, of which, the Company elected to account for lease and non-lease components in its contracts as a single lease component for all asset classes, to adopt the land easement practical expedient, which allows the Company to apply ASC 842 prospectively to new or modified land easements beginning January 1, 2019, and to not apply the recognition requirements of ASC 842 to leases with a lease term of twelve months or less. The Company's leasing activities as a lessor are negligible.
During the three months ended March 31, 2019, the Company incurred $1.2 million in new right-of-use assets and liabilities. The Company’s right-of-use assets and liabilities are recognized at their discounted present value on the balance sheet at $32.0 million and $32.8 million  as of March 31, 2019, respectively. All leases recognized on the Company's balance sheet are classified as operating leases, which include leases related to the asset classes reflected in the table below (in thousands):
 
 
Right-of-use Asset
 
Right-of-use Liability
Field equipment (1)
$
28,466

$
28,466

Corporate leases
 
2,993

 
3,782

Vehicles
 
540

 
540

Total
$
31,999

$
32,788

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

The lease amounts disclosed are presented on a gross basis. A portion of these costs may have been or will be billed to other working interest owners, and the Company's net share of these costs once paid are included in property and equipment, lease operating expenses, or general and administrative expenses, as applicable.
The Company recognizes lease expense on a straight-line basis excluding short-term and variable lease payments which are recognized as incurred. Short-term lease cost represents payments for leases with a lease term of one year or less, excluding leases with a term of one month or less. Short-term leases include drilling rigs and other equipment. Drilling rig contracts are structured based on an allotted number of wells to be drilled consecutively at a daily operating rate. Short-term drilling rig costs include a non-lease labor component, which is treated as a single lease component.
        
The following table summarizes the components of the Company's gross operating lease costs incurred during the three months ended March 31, 2019 (in thousands):
 
 
Amount
Operating lease cost (1)
$
2,350

Short-term lease cost
 
1,822

Variable lease cost (2)
 
20

Sublease income (3)
 
(87
)
Total lease cost
$
4,105

____________________________
(1) Includes office rent expense of $0.3 million .
(2) Variable lease cost represents differences between minimum lease obligations and actual costs incurred for certain leases that do not have fixed payments related to both lease and non-lease components. Such incremental costs include lease payment increases or decreases driven by market price fluctuations and leased asset maintenance costs.
(3) The Company subleased a portion of its office space for the remainder of the office lease term.

The Company does not have any leases with an implicit interest rate that can be readily determined. As a result, the Company used the incremental borrowing rate, based on the Current Credit Facility benchmark rate, adjusted for facility utilization and lease term, to calculate the respective discount rates. Please refer to Note 5 - Long-term Debt for additional information.

9

The Company's weighted-average lease term and discount rate used during the three months ended March 31, 2019 are as follows:
 
 
Three Months Ended March 31, 2019
Weighted-average lease term (years)
 
3.88

Weighted-average discount rate
 
4.33
%
Minimum future commitments by year for the Company's long-term operating leases as of March 31, 2019 are presented in the table below. Such commitments are reflected at undiscounted values and are reconciled to the discounted present value recognized on the balance sheet as follows (in thousands):
 
 
Amount
Remainder of 2019
$
7,276

2020
 
9,389

2021
 
8,678

2022
 
7,254

2023
 
2,932

Thereafter
 
39

Total lease payments
$
35,568

Less: imputed interest
 
(2,780
)
Total lease liability
$
32,788

NOTE 4 - ACCOUNTS PAYABLE AND ACCRUED EXPENSES
Accounts payable and accrued expenses contain the following (in thousands):
 
As of March 31, 2019
 
As of December 31, 2018
Accrued drilling and completion costs
$
27,892

 
$
33,602

Accounts payable trade
2,233

 
11,532

Accrued general and administrative expense
1,725

 
12,728

Accrued lease operating expense
3,297

 
2,183

Accrued interest
605

 
241

Accrued oil and gas hedging
380

 
—

Accrued production and ad valorem taxes and other
19,889

 
19,104

Total accounts payable and accrued expenses
$
56,021

 
$
79,390

NOTE 5 - LONG-TERM DEBT  
Current Credit Facility
On December 7, 2018, the Company entered into a reserve-based revolving facility, as the borrower, with JPMorgan Chase Bank, N.A., as the administrative agent, and a syndicate of financial institutions, as lenders (the “Current Credit Facility”). The Current Credit Facility has an aggregate original commitment amount of  $750.0 million  and matures on December 7, 2023. The initial borrowing base is  $350.0 million , and the first scheduled borrowing base redetermination is to occur in May 2019, with subsequent semi-annual redeterminations thereafter. 
Borrowings under the Current Credit Facility bear interest at a per annum rate equal to, at the option of the Company, either (i) a London InterBank Offered Rate (“LIBOR”), subject to a  0%  LIBOR floor plus a margin of  1.75%  to  2.75% , based on the utilization of the Current Credit Facility (the “Eurodollar Rate”) or (ii) a fluctuating interest rate per annum equal to the greatest of (a) the rate of interest publicly announced by JPMorgan Chase Bank, N.A. as its prime rate, (b) the rate of interest published by the Federal Reserve Bank of New York as the federal funds effective rate, (c) the rate of interest published by the Federal Reserve Bank of New York as the overnight bank funding rate and (d) a LIBOR offered rate for a one month interest period, subject to a  0%  LIBOR floor plus a margin of  0.75%  to  1.75% , based on the utilization of the Current Credit Facility (the “Reference Rate”). Interest on borrowings that bear interest at the Eurodollar Rate shall be payable on the last day of the

10

applicable interest period selected by the Company, which shall be one, two, three, or six months, and interest on borrowings that bear interest at the Reference Rate shall be payable quarterly in arrears. 
The Current Credit Facility is guaranteed by all wholly-owned subsidiaries of the Company (each, a “Guarantor” and, together with the Company, the “Credit Parties”), and is secured by first priority security interests on substantially all assets of each Credit Party, subject to customary exceptions.
The Current Credit Facility contains customary representations and affirmative covenants. The Current Credit Facility also contains customary negative covenants, which, among other things, and subject to certain exceptions, include restrictions on (i) liens, (ii) indebtedness, guarantees and other obligations, (iii) restrictions in agreements on liens and distributions, (iv) mergers or consolidations, (v) asset sales, (vi) restricted payments, (vii) investments, (viii) affiliate transactions, (ix) change of business, (x) foreign operations or subsidiaries, (xi) name changes, (xii) use of proceeds, letters of credit, (xiii) gas imbalances, (xiv) hedging transactions, (xv) additional subsidiaries, (xvi) changes in fiscal year or fiscal quarter, (xvii) operating leases, (xviii) prepayments of certain debt and other obligations, (xix) sales or discounts of receivables, and (xx) dividend payments. The Credit Parties are subject to certain financial covenants under the Current Credit Facility, including, without limitation, tested on the last day of each fiscal quarter, (i) a maximum ratio of the Company’s consolidated indebtedness (subject to certain exclusions) to earnings before interest, income taxes, depreciation, depletion, and amortization, exploration expense, and other non-cash charges (“EBITDAX”) of  4.00  to  1.00  and (ii) a current ratio, as defined in the agreement, inclusive of the unused Commitments then available to be borrowed, to not be less than  1.00  to  1.00 . The Company was in compliance with all covenants as of March 31, 2019, and through the filing date of this report.
The Company had  $65.0 million  and $50.0 million outstanding on the Current Credit Facility as of March 31, 2019 and December 31, 2018, respectively.
In connection with the Current Credit Facility, the Company capitalized a total of $2.5 million  in deferred financing costs, of which  $1.8 million  and  $0.5 million  of the total post amortization net capitalized amounts are presented within other noncurrent assets and prepaid expenses and other line items, respectively, in the accompanying condensed consolidated balance sheets (“balance sheets”) as of March 31, 2019.
Prior Credit Facility
Upon emergence from bankruptcy, the Company entered into a revolving credit facility, as the borrower, with KeyBank National Association, as the administrative agent, and certain lenders party thereto (the “Prior Credit Facility”). The borrowing base was  $191.7 million  and had a maturity date of March 31, 2021.
The Prior Credit Facility stated the Company's leverage ratio of indebtedness to EBITDAX was not to exceed  3.50  to  1.00 , the minimum current ratio must be 1.00  to  1.00 , and the minimum interest coverage ratio of trailing twelve-month EBITDAX to trailing twelve-month interest expense must be  2.50  to  1.00  as of the end of the respective fiscal quarter. During the period the Prior Credit Facility was outstanding, the Company was in compliance with all covenants.

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

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


11

NOTE 6 - COMMITMENTS AND CONTINGENCIES
Legal Proceedings 
From time to time, the Company is involved in various commercial and regulatory claims, litigation, and other legal proceedings that arise in the ordinary course of its business. The Company assesses these claims in an effort to determine the degree of probability and range of possible loss for potential accrual in its condensed consolidated financial statements. In accordance with 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 its 2018 Form 10-K, the Company and the Colorado Department of Public Health and Environment (“CDPHE”) agreed to a Compliance Order on Consent (the “COC”) resolving the matters addressed by a compliance advisory issued to the Company for certain storage tank facilities located in the Wattenberg Field with respect to applicable air quality regulations. The COC further set forth compliance requirements and criteria for continued operations. The Company adopted procedures and processes to address the monitoring, reporting, and control of air emissions. In order to be in compliance, the Company has incurred approximately $1.3 million during 2017 through 2018 and anticipates spending approximately $3.0 million during 2019 through 2022. The COC can be terminated after four years with a showing of substantial compliance and CDPHE approval.
In February 2019, the Company was sent a notice of intent to sue (“NOI”) letter by WildEarth Guardians (“WEG”), an environmental non-governmental organization, alleging failure to obtain required permits under the federal Clean Air Act before constructing and operating well production facilities in the ozone non-attainment area around the Denver Metropolitan and North Front Range of Colorado, among other things. The Company is one of seven operators in the Wattenberg Field to receive such an NOI letter from WEG, and these letters appear to challenge long-established federal and state regulations and policies for permitting the construction and initial operation of upstream oil and gas production facilities in Colorado and elsewhere under the Clean Air Act and state counterpart statutes.
On May 3, 2019, WEG filed a lawsuit against the Company and the other six operators who received the NOI, alleging claims consistent with those contained in the NOI letters. Because the allegations made in the lawsuit are based on novel and unprecedented interpretations of complex federal and state air quality laws and regulations, it is not possible for the Company to determine at this time whether the allegations have merit but the Company will vigorously defend against such allegations and will coordinate as much as possible with state and federal permitting authorities to maintain the validity of its current and future air permits for such facilities.
Commitments
The purchase agreement to deliver fixed determinable quantities of crude oil to NGL became effective on April 28, 2017. The 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 gross volume commitments, which are set in six-month periods beginning in January 2018. During 2018, the average minimum gross volume commitment was approximately 10,100 barrels per day, and the minimum gross volume commitment increased by approximately 41% from 2018 to 2019 and will increase approximately 3% each year thereafter for the remainder of the contract, to a maximum of approximately 16,000 gross barrels per day. The aggregate financial commitment fee over the remaining term, based on the minimum gross volume commitment schedule (as defined in the agreement) and the applicable differential fee, is $127.7 million as of March 31, 2019 . Upon notifying NGL at least twelve months prior to the expiration date of the NGL agreement, the Company may elect to extend the term of the NGL agreement for up to three additional years.

12

The annual minimum commitment payments under the NGL agreement for the next five years as of March 31, 2019 are presented below (in thousands):
 
 
NGL Gross Commitments(1)
2019
 
11,026

2020
 
27,949

2021
 
28,791

2022
 
29,485

2023
 
30,448

2024 and thereafter
 
—

Total
$
127,699

_______________________________
(1) The above calculation is based on the minimum gross 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 2018 Form 10-K. Refer to Note 3 - Leases , for lease commitments.
NOTE 7 - STOCK-BASED COMPENSATION
2017 Long Term Incentive Plan
Upon emergence from bankruptcy, the Company adopted a new Long Term Incentive Plan (the “2017 LTIP”), as established by the pre-emergence Board of Directors, which allows for the issuance of restricted stock units (“RSUs”), performance stock units (“PSUs”), and options. Upon emergence from bankruptcy, the Company reserved  2,467,430  shares of the new common stock for issuance under the 2017 LTIP. See below for further discussion of awards granted under the 2017 LTIP.
Restricted Stock Units
The 2017 LTIP allows for the issuance of RSUs to members of the Board of Directors (the “Board”) and employees of the Company at the discretion of the Board. Each RSU represents one share of the Company's common stock to be released from restriction upon completion of the vesting period. The awards typically vest in one-third increments over three years. The 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, 2019 . Total expense recorded for RSUs, inclusive of grants to the members of the Board, for the three months ended March 31, 2019 was $1.1 million . As of March 31, 2019 , unrecognized compensation cost for RSUs was $9.1 million and will be amortized through 2023 .
A summary of the status and activity of non-vested restricted stock units is presented below:
 
Restricted Stock Units
 
Weighted-
Average
Grant-Date
Fair Value    
Non-vested at beginning of year
480,835

 
$
30.83

Granted
—

 
$
—

Vested
(18,089
)
 
$
33.40

Forfeited
(1,073
)
 
$
28.66

Non-vested at end of quarter
461,673

 
$
30.73

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

13

The 2017 LTIP allows for the issuance of PSUs to employees at the sole discretion of the Board. The number of shares of the Company’s common stock that may be issued to settle PSUs range from zero to two times the number of PSUs awarded. The PSUs vest in their entirety at the end of the three -year performance period. The total number of PSUs granted is evenly split between two performance criterion. The first criterion is based on a comparison of the Company’s absolute and relative total shareholder return (“TSR”) for the performance period compared with the TSRs of a group of peer companies for the same performance period. The TSR for the Company and each of the peer companies is determined by dividing (A)(i) the volume-weighted average share price for the last 30 trading days of the performance period, minus (ii) the volume-weighted average share price for the 30 trading days preceding the beginning of the performance period, by (B) the volume-weighted average share price for the 30 trading days preceding the beginning of the performance period. The second criterion is based on the Company's average annual return on capital employed (“ROCE”) for each year during the three-year performance period. Compensation expense associated with PSUs is recognized as general and administrative expense over the performance period.
The fair value of the PSUs was measured at the grant date with a stochastic process method using a Brownian Motion simulation. A stochastic process is a mathematically defined equation that can create a series of outcomes over time. These outcomes are not deterministic in nature, which means that by iterating the equations multiple times, different results will be obtained for those iterations. In the case of the Company’s PSUs, the Company could not predict with certainty the path its stock price or the stock prices of its peers would take over the performance period. By using a stochastic simulation, the Company created multiple prospective stock pathways, statistically analyzed these simulations, and ultimately made inferences regarding the most likely path the stock price would take. As such, because future stock prices are stochastic, or probabilistic with some direction in nature, the stochastic method, specifically the Brownian Motion Model, was deemed an appropriate method by which to determine the fair value of the portion of the PSUs tied to the TSR. Significant assumptions used in this simulation include the Company’s expected volatility, risk-free interest rate based on U.S. Treasury yield curve rates with maturities consistent with the performance period, as well as the volatilities for each of the Company’s peers.
There were no PSUs granted during the three months ended March 31, 2019 . Total compensation recorded for PSUs for the three months ended March 31, 2019 was $0.1 million . As of March 31, 2019 , unrecognized compensation costs for PSUs was $1.0 million and will be amortized through 2020.
A summary of the status and activity of performance stock units is presented below:
 
Performance Stock Units
 
Weighted-
Average
Grant-Date
Fair Value    
Non-vested at beginning of year
53,689

 
$
29.92

Granted  (1)
—

 
$
—

Vested (1)
(2,598
)
 
$
29.92

Forfeited (1)
—

 
$
—

Non-vested at end of quarter (1)
51,091

 
$
29.92

___________________________
(1)
The number of awards assumes that the associated performance condition is met at the target amount. The final number of shares of the Company’s common stock issued may vary depending on the performance multiplier, which ranges from zero to two, depending on the level of satisfaction of the performance condition.
Stock Options
The 2017 LTIP allows for the issuance of stock options to the Company's employees at the sole discretion of the Board of Directors. Options expire ten years from the grant date unless otherwise determined by the Board of Directors. Compensation expense on the stock options is recognized as general and administrative expense over the vesting period of the award.
There were no stock options granted during the three months ended March 31, 2019 . Total expense recorded for stock options for the three months ended March 31, 2019 was $0.2 million . As of March 31, 2019 , unrecognized compensation cost for stock options was $0.7 million and will be amortized through 2020 .
Stock options are valued using a Black-Scholes Model where expected volatility is based on an average historical volatility of a peer group selected by management over a period consistent with the expected life assumption on the grant date, the risk-free rate of return is based on the U.S. Treasury constant maturity yield on the grant date with a remaining term equal to the expected term of the awards, and the Company’s expected life of stock option awards is derived from the midpoint of the average vesting time and contractual term of the awards.

14

A summary of the status and activity of non-vested stock options is presented below:
 
Stock Options
 
Weighted-
Average
Exercise Price
 
Weighted-Average Remaining Contractual Term (in years)
 
Aggregate Intrinsic Value (in thousands)
Outstanding at beginning of year
132,809

 
$
34.36

 
6.7

 
$
—

Granted
—

 
—

 
—

 
$
—

Exercised
—

 
—

 
—

 
$
—

Forfeited
(25,470
)
 
$
34.36

 
—

 
$
—

Outstanding at end of quarter
107,339

 
$
34.36

 
7.96

 
$
—

Number of options outstanding and exercisable

36,674

 
$
34.36

 
7.74

 
$
—

NOTE 8 - FAIR VALUE MEASUREMENTS
The Company follows fair value measurement authoritative guidance, which defines fair value, establishes a framework for using fair value to measure assets and liabilities, and expands disclosures about fair value measurements. The authoritative accounting guidance defines fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. The statement establishes a hierarchy for inputs used in measuring fair value that maximizes the use of observable inputs and minimizes the use of unobservable inputs by requiring that the most observable inputs be used when available. 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  
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 and their classification within the fair value hierarchy (in thousands):
 
As of March 31, 2019
 
Level 1
 
Level 2
 
Level 3
Derivative assets (1)
$
—

 
$
6,400

 
$
—

Derivative liabilities (1)
$
—

 
$
4,889

 
$
—

 
As of December 31, 2018
 
Level 1
 
Level 2
 
Level 3
Derivative assets (1)
$
—

 
$
38,272

 
$
—

Derivative liabilities (1)
$
—

 
$
183

 
$
—

Asset retirement obligations (2)
$
—

 
$
—

 
$
1,490

____________________________
(1)
This represents a financial asset or liability that is measured at fair value on a recurring basis.
(2)
Represents the revision to estimates of the asset retirement obligation, which is a non-financial liability that is measured at fair value on a nonrecurring basis. Please refer to the Asset Retirement Obligation  section below for additional discussion.

15

Derivatives
Fair value of all derivative instruments are estimated with industry-standard models that consider various assumptions, including quoted forward prices for commodities, time value of money, volatility factors and current market and contractual prices for the underlying instruments, as well as other relevant economic measures. All valuations were compared against counterparty statements to verify the reasonableness of the estimate. The Company’s commodity swaps and collars were validated by observable transactions for the same or similar commodity options using the NYMEX futures index, and were designated as Level 2 within the valuation hierarchy.
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, standard amortization, and estimated reserve values. During the three months ended March 31, 2019, the Company incurred its standard annual amortization of $0.9 million on its emergence leases that were not held by production as disclosed in the abandonment and impairment of unproved properties line item in the accompanying statements of operations.
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, 2019 . The Company had $1.5 million of asset retirement obligations recorded at fair value as of December 31, 2018 .
Long-term Debt
The Company's Current Credit Facility approximates fair value as the applicable interest rates are floating. The Company had $65.0 million and $50.0 million outstanding under the Current Credit Facility as of March 31, 2019 and December 31, 2018, respectively.
NOTE 9 - ASSET RETIREMENT OBLIGATIONS
The Company recognizes an estimated liability for future costs to abandon its oil and gas properties. The fair value of the asset retirement obligation is recorded as a liability when incurred, which is typically at the time the asset is acquired or placed in service. There is a corresponding increase to the carrying value of the asset, which is included in the proved properties line item in the accompanying balance sheets. The Company depletes the amount added to proved properties and recognizes expense in connection with accretion of the discounted liability over the remaining estimated economic lives of the properties.
The Company’s estimated asset retirement obligation liability is based on historical experience in abandoning wells, estimated economic lives, estimated costs to abandon the wells, and regulatory requirements. The liability is discounted using the credit-adjusted risk-free rate estimated at the time the liability is incurred, which ranges from 5% to 7% .
A roll-forward of the Company's asset retirement obligation is as follows (in thousands):
Beginning balance as of December 31, 2018
$
29,405

Liabilities settled
 
(563
)
Additions
 
79

Accretion expense
 
457

Ending balance as of March 31, 2019
$
29,378


NOTE 10 - DERIVATIVES
The Company enters into commodity derivative contracts to mitigate a portion of its exposure to potentially adverse market changes in commodity prices and the associated impact on cash flows. All contracts are entered into for other-than-

16

trading purposes. The Company’s derivatives include swaps and collars for oil and natural gas, and none of the derivative instruments qualifies as having hedging relationships.
In a typical commodity swap agreement, if the agreed upon published third-party index price is lower than the swap fixed price, the Company receives the difference between the index price and the agreed upon swap fixed price. If the index price is higher than the swap fixed price, the Company pays the difference.
A cashless collar arrangement establishes a floor and ceiling price on future oil and gas production. When the settlement price is above the ceiling price, the Company pays the difference between the settlement price and the ceiling price. When the settlement price is below the floor price, the Company receives the difference between the settlement price and floor price. In the event that the settlement price is between the ceiling and the floor, no payment or receipt occurs.
A basis swap arrangement guarantees a price differential from a specified delivery point. The Company receives the difference between the price differential and the stated terms, if the price differential is greater than the stated terms. The Company pays the difference between the price differential and the stated terms, if the stated terms are greater than the price differential.
    


17

As of March 31, 2019 , the Company had entered into the following commodity derivative contracts:
 
 
Crude Oil
(NYMEX WTI)
 
Natural Gas
(NYMEX Henry Hub)
 
Natural Gas
(CIG)
 
 
Bbls/day
 
Weighted Avg. Price per Bbl
 
MMBtu/day
 
Weighted Avg. Price per MMBtu
 
MMBtu/day
 
Weighted Avg. Price per MMBtu
2Q19
 
 
 
 
 
 
 
 
 
 
 
 
Cashless Collar
 
6,330

 
$54.51/$68.74
 
2,505

 
$2.75/$3.22
 
—

 
—
Swap
 
3,500

 
$57.84
 
—

 
—
 
19,203

 
$2.15
3Q19
 
 
 
 
 
 
 
 
 
 
 
 
Cashless Collar
 
4,000

 
$58.13/$75.54
 
—

 
—
 
—

 
—
Swap
 
5,000

 
$59.92
 
—

 
—
 
22,500

 
$2.13
4Q19
 
 
 
 
 
 
 
 
 
 
 
 
Cashless Collar
 
4,000

 
$58.13/$75.54
 
—

 
—
 
—

 
—
Swap
 
5,000

 
$59.92
 
—

 
—
 
22,500

 
$2.13
1Q20
 
 
 
 
 
 
 
 
 
 
 
 
Cashless Collar
 
3,000

 
$55.00/$62.00
 
—

 
—
 
—

 
—
Swap
 
3,000

 
$63.48
 
—

 
—
 
2,500

 
$2.40
2Q20
 
 
 
 
 
 
 
 
 
 
 
 
Cashless Collar
 
1,000

 
$55.00/$62.00
 
—

 
—
 
—

 
—
As of the filing date of this report, the Company had entered into the following commodity derivative contracts:
 
 
Crude Oil
(NYMEX WTI)
 
Natural Gas
(NYMEX Henry Hub)
 
Natural Gas
(CIG)
 
 
Bbls/day
 
Weighted Avg. Price per Bbl
 
MMBtu/day
 
Weighted Avg. Price per MMBtu
 
MMBtu/day
 
Weighted Avg. Price per MMBtu
2Q19
 
 
 
 
 
 
 
 
 
 
 
 
Cashless Collar
 
6,330

 
$54.51/$68.74
 
2,505

 
$2.75/$3.22
 
—

 
—

Swap
 
3,500

 
$57.84
 
—

 
—
 
19,203

 
$2.15
3Q19
 
 
 
 
 
 
 
 
 
 
 
 
Cashless Collar
 
4,000

 
$58.13/$75.54
 
—

 
—
 
—

 
—
Swap
 
5,000

 
59.92
 
—

 
—
 
22,500

 
$2.13
4Q19
 
 
 
 
 
 
 
 
 
 
 
 
Cashless Collar
 
4,000

 
$58.13/$75.54
 
—

 
—
 
—

 
—
Swap
 
5,000

 
$59.92
 
—

 
—
 
22,500

 
$2.13
1Q20
 
 
 
 
 
 
 
 
 
 
 
 
Cashless Collar
 
5,000

 
$55.00/$62.88
 
—

 
—
 
—

 
—
Swap
 
3,000

 
$63.48
 
—

 
—
 
2,500

 
$2.40
2Q20
 
 
 
 
 
 
 
 
 
 
 
 
Cashless Collar
 
5,000

 
$55.00/$63.33
 
—

 
—
 
—

 
—
3Q20
 
 
 
 
 
 
 
 
 
 
 
 
Cashless Collar
 
2,000

 
$55.00/$63.14
 
—

 
—
 
—

 
—
4Q20
 
 
 
 
 
 
 
 
 
 
 
 
Cashless Collar
 
2,000

 
$55.00/$63.14
 
—

 
—
 
—

 
—



18

Derivative Assets and Liabilities Fair Value
  The Company’s commodity derivatives are measured at fair value and are included in the accompanying balance sheets as derivative assets and liabilities. The following table contains a summary of all the Company’s derivative positions reported on the accompanying balance sheets for the periods below (in thousands):
 
 
 
As of March 31, 2019
 
As of December 31, 2018
 
Balance Sheet Location
 
Fair Value
 
Fair Value
Derivative Assets:
 
 
 
 
 

Commodity contracts
Current assets
 
$
6,400

 
$
34,408

Commodity contracts
Noncurrent assets
 
—

 
3,864

Derivative Liabilities:
 
 
 

 
 

Commodity contracts
Current liabilities
 
(4,889
)
 
(183
)
Commodity contracts
Long-term liabilities
 
—

 
—

Total derivative assets, net
 
 
$
1,511

 
$
38,089

The following table summarizes the components of the derivative loss presented on the accompanying statements of operations for the periods below (in thousands):
 
Three Months Ended March 31,
 
2019
 
2018
Derivative cash settlement gain (loss):
 
 
 

Oil contracts
$
2,078

 
$
(4,506
)
Gas contracts
(1,142
)
 
194

Total derivative cash settlement gain (loss) (1)
$
936

 
$
(4,312
)
 
 
 
 
Change in fair value liability
(37,480
)
 
(4,430
)
 
 
 
 
Total derivative loss (1)
$
(36,544
)
 
$
(8,742
)
_______________________________
(1)
Total derivative loss and total derivative cash settlement gain (loss) for the three months ended March 31, 2019 and 2018 are reported in the derivative loss line item and derivative cash settlements line item in the accompanying statements of cash flows, within cash flows from operating activities. 
NOTE 11 - EARNINGS PER SHARE
The Company issues RSUs, which represent the right to receive, upon vesting, one share of the Company's common stock. The number of potentially dilutive shares related to RSUs is based on the number of shares, if any, that would be issuable at the end of the respective reporting period, assuming that date was the end of the vesting period. The Company issues PSUs, which represent the right to receive, upon settlement of the PSUs, a number of shares of the Company's common stock that range from zero to two times the number of PSUs granted on the award date. The number of potentially dilutive shares related to PSUs is based on the number of shares, if any, that would be issuable at the end of the respective reporting period, assuming that date was the end of the performance period applicable to such PSUs. The Company issued stock options and warrants, which both represent the right to purchase the Company's common stock at a specified price. The number of potentially dilutive shares related to the stock options is based on the number of shares, if any, that would be exercised at the end of the respective reporting period, assuming that date was the end of such stock options' term. The number of potentially dilutive shares related to the warrants is based on the number of shares, if any, that would be exercisable at the end of the respective reporting period.
Please refer to Note 7 - Stock-Based Compensation for additional discussion.

19

The RSUs, PSUs, stock options, and warrants of the Company are all non-participating securities, and therefore, the Company uses the treasury stock method to calculate earnings per share as shown in the following table (in thousands, except per share amounts):
 
Three Months Ended March 31,
 
2019
 
2018
Net income (loss)
$
(6,993
)
 
$
13,870

 
 
 
 
Basic net income (loss) per common share
$
(0.34
)
 
$
0.68

 
 
 
 
Diluted net income (loss) per common share
$
(0.34
)
 
$
0.68

 
 
 
 
Weighted-average shares outstanding - basic
20,557

 
20,454

Add: dilutive effect of contingent stock awards
—

 
16

Weighted-average shares outstanding - diluted
20,557

 
20,470

There were 173,252 and 259,924 shares which were anti-dilutive for the three months ended March 31, 2019 and 2018, respectively. The Company was in a net loss position for the three months ended March 31, 2019, which made all potentially dilutive shares anti-dilutive.
The exercise price of the Company's warrants was in excess of the Company's stock price; therefore, they were excluded from the earnings per share calculation.    
NOTE 12 - INCOME TAXES
The Company has fully implemented the Tax Cuts and Jobs Act, which made significant changes to U.S. federal income tax law, including a reduction in the federal corporate tax rate to 21%, effective January 1, 2018.
The Company uses the asset and liability method of accounting for deferred income taxes. Deferred tax assets and liabilities are determined based on the temporary differences between the financial statement and tax basis of assets and liabilities. Deferred tax assets or liabilities at the end of each period are determined using the tax rate in effect at that time. There is a full valuation allowance on the Company's net deferred tax asset causing the Company’s current rate to differ from the U.S. statutory income tax rate.
As of March 31, 2019 , the Company had  no  unrecognized tax benefits. The Company’s management does not believe that there are any new items or changes in facts or judgments that would impact the Company's tax position taken thus far in 2019 .

20

Item 2.    Management’s Discussion and Analysis of Financial Condition and Results of Operations.
 
The following discussion and analysis of our financial condition and results of operations should be read in conjunction with “Management’s Discussion and Analysis of Financial Condition and Results of Operations” contained in our Annual Report on Form 10-K for the year ended December 31, 2018, as well as the unaudited condensed consolidated financial statements and notes thereto included in this Quarterly Report on Form 10-Q.
Executive Summary  
We are an independent Denver-based exploration and production company focused on the acquisition, development, and extraction of oil and associated liquids-rich natural gas in the United States. Our oil and liquids-weighted assets and operations are concentrated in the rural portions of the Wattenberg Field in Colorado. Our development and extraction activities are primarily directed at the horizontal development of the Niobrara and Codell formations in the DJ Basin. We intend to continue the development of our reserves and increase production on our multi-year inventory of identified potential drilling locations and through acquisitions that meet our strategic and financial objectives. The majority of our revenues are generated through the sale of oil, natural gas, and natural gas liquids production.
The Company’s primary objective is to maximize shareholder returns by responsibly developing our oil and gas resources. We seek to balance production growth with maintaining a conservative balance sheet. Key aspects of our strategy include multi-well pad development across our leasehold, enhanced completions through continuous design evaluation, continuous safety improvement, strict adherence to health and safety regulations, and environmental stewardship.
Financial and Operating Results
Our financial and operational results include:
•
Lease operating expense decreased $5.0 million or $4.02 per Boe for the three months ended March 31, 2019 when compared to the same period during 2018, which is inclusive of our Mid-Continent assets that were sold on August 6, 2018;
•
Sales volumes increased 24% for the three months ended March 31, 2019 when compared to the same period during 2018;
•
Total liquidity of $317.7 million at March 31, 2019 , consisting of cash on hand plus funds available under our Current Credit Facility. Please refer to Liquidity and Capital Resources below for additional discussion;
•
Cash flows provided by operating activities for the three months ended March 31, 2019 was $ 41.7 million , as compared to cash flows provided by operating activities of $15.9 million during the three months ended March 31, 2018. Please refer to  Liquidity and Capital Resources  below for additional discussion;
•
Incurred capital expenditures, inclusive of accruals, of $44.8 million during the three months ended March 31, 2019; and
•
Construction of the Company’s new oil gathering line to Riverside Terminal is underway and, as reflected in our annual guidance, is expected to lower corresponding oil differentials in the second half of 2019 by $1.25 - $1.50.
Rocky Mountain Infrastructure
The Company's gathering, treating and production facilities, maintained under its Rocky Mountain Infrastructure, LLC (“RMI”) subsidiary, provide many operational benefits to the Company. The RMI system reduces gathering system pressures at the wellhead, improving hydrocarbon recovery. Additionally, with eleven interconnects to four different natural gas processors, RMI helps ensure that the Company's production is not constrained by any single midstream service provider. Furthermore, the system reduces facility site footprints, leading to more cost-efficient operations and reduced surface disturbance. The net book value of the Company's RMI assets was $125.7 million as of March 31, 2019.
Outlook for 2019
The Company's 2019 capital budget of $230.0 million to $255.0 million assumes a continuous one-rig development pace. The drilling and completion portion of the budget is expected to be approximately $210.0 million to $220.0 million, which will support drilling 59 gross wells and turning to sales 45 gross wells. Included in the drilling completion budget is $15.0 million for non-operated capital expenditures. Of the operated wells planned to be drilled, approximately 26 are extended reach lateral (“XRL”) wells and 33 are standard reach lateral (“SRL”) wells. Of the wells planned to be completed, 16 are XRL

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wells, five are medium reach lateral (“MRL”) wells, and 24 are SRL wells. The remaining 2019 capital budget of $20.0 million to $35.0 million is to support infrastructure and leasehold costs. Actual capital expenditures could vary significantly based on, among other things, market conditions, commodity prices, drilling and completion costs, well results, acquisitions or divestitures, and changes in the borrowing base under our Current Credit Facility.

Recent Developments

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

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

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

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




22
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Results of Operations
The following table summarizes our revenues, sales volumes, and average sales prices for the periods indicated:
 
Three Months Ended March 31,
 
 
 
 
 
 
2019
 
2018
 
Change
 
Percent Change
Revenues (in thousands):
 
 

 
 
 

 
 
 
 
 
Crude oil sales (1)
$
60,211

 
$
51,839

 
$
8,372

 
16
 %
Natural gas sales (2)
 
6,772

 
 
5,934

 
 
838

 
14
 %
Natural gas liquids sales (3)
 
4,348

 
 
6,009

 
 
(1,661
)
 
(28
)%
Product revenue
$
71,331

 
$
63,782

 
$
7,549

 
12
 %
 
 
 
 
 
 
 
 
 
 
 
Sales Volumes:
 
 
 
 
 
 
 
 
 
 
Crude oil (MBbls) (4)
 
1,208.2

 
 
895.4

 
 
312.8

 
35
 %
Natural gas (MMcf) (5)
 
2,198.4

 
 
2,135.2

 
 
63.2

 
3
 %
Natural gas liquids (MBbls) (6)
 
291.6

 
 
257.6

 
 
34.0

 
13
 %
Crude oil equivalent (MBoe) (3)
 
1,866.2

 
 
1,508.8

 
 
357.4

 
24
 %
 
 
 
 
 
 
 
 
 
 
 
Average Sales Prices (before derivatives) (7) :
 
 

 
 
 

 
 
 
 
 
Crude oil (per Bbl)
$
49.83

 
$
57.89

 
$
(8.06
)
 
(14
)%
Natural gas (per Mcf)
$
3.08

 
$
2.78

 
$
0.30

 
11
 %
Natural gas liquids (per Bbl)
$
14.91

 
$
23.33

 
$
(8.42
)
 
(36
)%
Crude oil equivalent (per Boe) (3)
$
38.22

 
$
42.27

 
$
(4.05
)
 
(10
)%
 
 
 
 
 
 
 
 
 
 
 
Average Sales Prices (after derivatives) (7) :
 
 
 
 
 
 
 
 
 
 
Crude oil (per Bbl)
$
51.55

 
$
52.86

 
$
(1.31
)
 
(2
)%
Natural gas (per Mcf)
$
2.56

 
$
2.87

 
$
(0.31
)
 
(11
)%
Natural gas liquids (per Bbl)
$
14.91

 
$
23.33

 
$
(8.42
)
 
(36
)%
Crude oil equivalent (per Boe) (3)
$
38.72

 
$
39.42

 
$
(0.70
)
 
(2
)%
_____________________________
(1)
Crude oil sales excludes $0.6 million and $0.1 million of oil transportation revenues from third parties, which do not have associated sales volumes, for the three months ended March 31, 2019 and 2018, respectively.
(2)
Natural gas sales excludes $0.7 million and $0.3 million of gas gathering revenues from third parties, which do not have associated sales volumes, for the three months ended March 31, 2019 and 2018, respectively.
(3)
Determined using the ratio of 6 Mcf of natural gas to 1 Bbl of crude oil.
(4)
Crude oil sales volumes includes 150.0 MBbls of sales volumes from the Mid-Continent region for the three months ended March 31, 2018. The Mid-Continent region assets were sold August 6, 2018, and therefore, no sales volumes were associated with the Mid-Continent region during the three months ended March 31, 2019.
(5)
Natural gas sales volumes includes 492.0 MMcf of sales volumes from the Mid-Continent region for the three months ended March 31, 2018. The Mid-Continent region assets were sold August 6, 2018, and therefore, no sales volumes were associated with the Mid-Continent region during the three months ended March 31, 2019.
(6)
Natural gas liquids sales volumes includes 40.3 MBbls of sales volumes from the Mid-Continent region for the three months ended March 31, 2018. The Mid-Continent region assets were sold August 6, 2018, and therefore, no sales volumes were associated with the Mid-Continent region during the three months ended March 31, 2019.
(7)
Derivatives economically hedge the price we receive for crude oil. For the three months ended March 31, 2019 , derivative cash settlement gains for oil contracts was $2.1 million , and the derivative cash settlement loss for natural gas contracts was $1.1 million. 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 10 - Derivatives of Part I, Item 1 of this report for additional disclosures.

 

23
Table of Contents

Operating revenues increased for the three months ended March 31, 2019 by 12% , to $71.3 million , compared to $63.8 million for the three months ended March 31, 2018. The increase was primarily due to a 24% increase in oil equivalent sales volumes, partially offset by a 10% decrease in oil equivalent pricing excluding the impact of derivatives.

The following table summarizes our operating expenses for the periods indicated:
 
Three Months Ended March 31,
 
 
 
 
 
 
2019
 
2018
 
Change
 
Percent Change
Expenses (in thousands):
 
 

 
 
 

 
 
 
 
 
Lease operating expense
$
5,426

 
$
10,459

 
$
(5,033
)
 
(48
)%
Gas plant and midstream operating expense
 
2,321

 
 
3,613

 
 
(1,292
)
 
(36
)%
Gathering, transportation, and processing
 
4,022

 
 
2,338

 
 
1,684

 
72
 %
Severance and ad valorem taxes
 
4,248

 
 
5,233

 
 
(985
)
 
(19
)%
Exploration
 
97

 
 
29

 
 
68

 
234
 %
Depreciation, depletion, and amortization
 
15,759

 
 
7,508

 
 
8,251

 
110
 %
Abandonment and impairment of unproved properties
 
879

 
 
2,502

 
 
(1,623
)
 
(65
)%
Unused commitments
 
—

 
 
21

 
 
(21
)
 
(100
)%
General and administrative
 
10,278

 
 
9,533

 
 
745

 
8
 %
Operating Expenses
$
43,030

 
$
41,236

 
$
1,794

 
4
 %
 
 
 
 
 
 
 
 
 
 
 
Selected Costs ($ per Boe):
 
 

 
 
 

 
 
 
 
 
Lease operating expense
$
2.91

 
$
6.93

 
$
(4.02
)
 
(58
)%
Gas plant and midstream operating expense
 
1.24

 
 
2.39

 
 
(1.15
)
 
(48
)%
Gathering, transportation, and processing
 
2.16

 
 
1.55

 
 
0.61

 
39
 %
Severance and ad valorem taxes
 
2.28

 
 
3.47

 
 
(1.19
)
 
(34
)%
Exploration
 
0.05

 
 
0.02

 
 
0.03

 
150
 %
Depreciation, depletion, and amortization
 
8.44

 
 
4.98

 
 
3.46

 
69
 %
Abandonment and impairment of unproved properties
 
0.47

 
 
1.66

 
 
(1.19
)
 
(72
)%
Unused commitments
 
—

 
 
0.01

 
 
(0.01
)
 
(100
)%
General and administrative
 
5.51

 
 
6.32

 
 
(0.81
)
 
(13
)%
Operating Expenses
$
23.06

 
$
27.33

 
$
(4.27
)
 
(16
)%
Lease operating expense.  Our lease operating expense (“LOE”) decreased $5.0 million , or 48% , to $5.4 million for the three months ended March 31, 2019 from $10.5 million for the three months ended March 31, 2018 , and decreased on an equivalent basis per Boe by 58% . During the three months ended March 31, 2019, the Company experienced decreases, when compared to the same period in 2018, in well servicing and maintenance costs of $3.2 million, compression costs of $0.9 million, and remediation and reclamation work of $0.7 million. The balance of the decrease in LOE was associated with our Mid-Continent assets that were owned during the three months ended March 31, 2018 and sold on August 6, 2018. LOE per unit decreased on a higher percentage basis due to the higher production recorded in the quarter ended March 31, 2019 as compared to the quarter ended March 31, 2018.
Gas plant and midstream operating expense.  Our gas plant and midstream operating expense decreased $1.3 million , or 36% , to $2.3 million for the three months ended March 31, 2019 from $3.6 million for the three months ended March 31, 2018, and decreased 48% on a per Boe basis during the comparable periods. The decrease was primarily due to the sale of our Mid-Continent assets on August 6, 2018. The first quarter of 2018 is inclusive of gas plant expense.
Gathering, transportation, and processing.  Gathering, transportation, and processing expense increased by $1.7 million , or 72% , from $2.3 million for the three months ended March 31, 2018 to $4.0 million for the three months ended March 31, 2019. The increase was primarily due to additional sales contracts becoming effective during the first quarter of 2019 with terms requiring the revenues and gathering, transportation, and processing expense to be shown on a gross basis. In

24
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addition to the new contracts, sales volumes increased 24% as compared to the three months ended March 31, 2018. Sales volumes have a direct correlation to gathering, transportation, and processing expense.
Severance and ad valorem taxes.  Our severance and ad valorem taxes decreased 19% to $4.2 million for the three months ended March 31, 2019 from $5.2 million for the three months ended March 31, 2018. Severance and ad valorem taxes decreased primarily due to a refund that was received within the first quarter of 2019.
Depreciation, depletion, and amortization.  Our depreciation, depletion, and amortization expense per Boe was $8.44 and $4.98 for the three months ended March 31, 2019 and 2018, respectively. The increase in depreciation, depletion, and amortization during the three months ended March 31, 2019 when compared to the three months ended March 31, 2018 primarily correlates to a $287.2 million increase in the depletable property base.
Abandonment and impairment of unproved properties.  The Company incurred $0.9 million and $2.5 million of abandonment and impairment of unproved properties costs during the three months ended March 31, 2019 and 2018, respectively. During the three months ended March 31, 2019, the Company incurred its standard annual amortization of $0.9 million on its emergence leases that were not held by production. During the three months ended March 31, 2018, the Company incurred impairment charges relating to non-core leases expiring.
General and administrative. Our general and administrative expense increased by $0.7 million to $10.3 million for the three months ended March 31, 2019 from $9.5 million for the three months ended March 31, 2018, and decreased by 13% on a per Boe basis between the comparable periods. The increase in general and administrative expense between the comparable periods is primarily due to a severance payment made to the Company's Senior Vice President, Finance and Planning upon separation from the Company.

Derivative loss.  Our derivative loss for the three months ended March 31, 2019 was $36.5 million as compared to a derivative loss of $8.7 million for the three months ended March 31, 2018. Our derivative loss is due to settlements and fair market value adjustments caused by market prices being higher than our contracted hedge prices. Please refer to  Note 10 - Derivatives of Part I, Item 1 of this report for additional discussion.
Interest expense.  Our interest expense for the three months ended March 31, 2019 and 2018 was $1.2 million and $0.4 million , respectively. The Company incurred $0.8 million in interest expense associated with its Current Credit Facility, $0.3 million in commitment fees on the available borrowing base under the Current Credit Facility, and $0.1 million due to the amortization of deferred financing costs during the three months ended March 31, 2019 . The Company incurred $0.1 million in interest expense associated with the Prior Credit Facility and $0.3 million in commitment fees on the available borrowing base under the Prior Credit Facility during the three months ended March 31, 2018. Average debt outstanding for the three months ended March 31, 2019 and 2018 was $64.7 million and $10.3 million, respectively.

Liquidity and Capital Resources
The Company's anticipated sources of liquidity include cash from operating activities, borrowings under the Current Credit Facility, proceeds from sales of assets, and potential proceeds from capital and/or debt markets. Our cash flows from operating activities are subject to significant volatility due to changes in commodity prices, as well as variations in our production. The prices for these commodities are driven by a number of factors beyond our control, including global and regional product supply and demand, weather, product distribution, refining and processing capacity, regulatory constraints, and other supply chain dynamics, among other factors. To mitigate some of the pricing risk, we have approximately 58% of our 2019 guided production hedged as of March 31, 2019 and as of the filing date of this report.
As of March 31, 2019 , our liquidity was $317.7 million , consisting of cash on hand of $32.7 million and $285.0 million of available borrowing capacity on the Current Credit Facility. Please refer to Note 5 - Long-term Debt in Part I, Item 1 above for additional discussion.
We anticipate investing approximately $230.0 million to $255.0 million, which will support drilling approximately 59 gross wells and turning to sales 45 gross wells in 2019.
Our weighted-average interest rates on borrowings from the Current Credit Facility was 4.69% for the three months ended March 31, 2019. As of March 31, 2019 and as of the date of filing, we had $65.0 million outstanding on our Current Credit Facility.

25
Table of Contents

The following table summarizes our cash flows and other financial measures for the periods indicated (in thousands):
 
Three Months Ended March 31,
 
2019
 
2018
Net cash provided by operating activities
$
41,721

 
$
15,903

Net cash used in investing activities
(36,788
)
 
(37,845
)
Net cash provided by financing activities
14,847

 
15,000

Cash, cash equivalents, and restricted cash
32,782

 
5,840

Acquisition of oil and gas properties
1,362

 
98

Exploration and development of oil and gas properties
36,503

 
37,664

Cash flows provided by operating activities
  The three months ended March 31, 2019 and 2018 include cash receipts and disbursements attributable to our normal operating cycle. See Results of Operations above for more information on the factors driving these changes.
Cash flows used in investing activities
Expenditures for development of oil and natural gas properties are the primary use of our capital resources. The Company spent $36.5 million and $37.7 million on the exploration and development of oil and gas properties during the three months ended March 31, 2019 and 2018, respectively. The decrease in capital expenditures among the periods is primarily due to timing of payments related to these activities.
Cash flows provided by financing activities
Net cash provided by financing activities for the three months ended March 31, 2019 and 2018 was $14.8 million and $15.0 million, respectively, primarily due to proceeds from our Current and Prior Credit Facility.
Non-GAAP Financial Measures
Adjusted EBITDAX represents earnings before interest, income taxes, depreciation, depletion, and amortization, exploration expense, and other non-cash and non-recurring charges. Adjusted EBITDAX excludes certain items that we believe affect the comparability of operating results and can exclude items that are generally non-recurring in nature or whose timing and/or amount cannot be reasonably estimated. Adjusted EBITDAX is a non-GAAP measure that we present because we believe it provides useful additional information to investors and analysts, as a performance measure, for analysis of our ability to internally generate funds for exploration, development, acquisitions, and to service debt. We are also subject to financial covenants under our Current Credit Facility based on adjusted EBITDAX ratios as further described Note 5 - Long-Term Debt in Part I, Item I of this document. In addition, adjusted EBITDAX is widely used by professional research analysts and others in the valuation, comparison, and investment recommendations of companies in the oil and gas exploration and production industry. Adjusted EBITDAX should not be considered in isolation or as a substitute for net income (loss), income (loss) from operations, net cash provided by operating activities, or other profitability or liquidity measures prepared under GAAP. Because adjusted EBITDAX excludes some, but not all items that affect net income (loss) and may vary among companies, the adjusted EBITDAX amounts presented may not be comparable to similar metrics of other companies.

The following table presents a reconciliation of the GAAP financial measure of net income (loss) to the non-GAAP financial measure of Adjusted EBITDAX.


26
Table of Contents

 
 
Three Months Ended March 31,
 
 
2019
 
2018
Net income (loss)
 
$
(6,993
)
 
$
13,870

Exploration
 
97

 
29

Depreciation, depletion, and amortization
 
15,759

 
7,508

Amortization of deferred financing costs
 
125

 
—

Abandonment and impairment of unproved properties
 
879

 
2,502

Unused commitments
 
—

 
21

Stock-based compensation (1)
 
1,380

 
1,008

Severance costs (1)
 
418

 
—

Gain on sale of oil and gas properties
 
(1,126
)
 
—

Interest expense
 
1,151

 
357

Derivative loss
 
36,544

 
8,742

Derivative cash settlements
 
936

 
(4,312
)
Adjusted EBITDAX
 
$
49,170

 
$
29,725

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

New Accounting Pronouncements  
Please refer to Note 2 — Basis of Presentation under Part I, Item 1 of this report for any recently issued or adopted accounting standards.
Critical Accounting Policies and Estimates
Information regarding our critical accounting policies and estimates is contained in Part II, Item 7 of our 2018 Form 10-K.  
Effects of Inflation and Pricing
Although the impact of inflation has been relatively insignificant in recent years, it is still a factor in the United States economy, and we tend to experience inflationary pressure on the cost of oilfield services and equipment as increasing oil and gas prices increase drilling activity in our areas of operations. Material changes in prices also impact the current revenue stream, estimates of future reserves, borrowing base calculations, depletion expense, impairment assessments of oil and gas properties, asset retirement obligation, and values of properties in purchase and sale transactions. Material changes in prices can impact the value of oil and gas companies and their ability to raise capital, borrow money, and retain personnel.
Off-Balance Sheet Arrangements  
Currently, we do not have any off-balance sheet arrangements that are not disclosed within this report.
Contractual Obligations
There have been no significant changes from our 2018 Form 10-K in our obligations and commitments, other than what is disclosed within Note 3 - Leases and Note 6 - Commitments and Contingencies under Part I, Item 1 of this report.
Cautionary Note Regarding Forward-Looking Statements
This Quarterly Report on Form 10-Q contains various statements, including those that express belief, expectation or intention, as well as those that are not statements of historic fact, that are forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities and Exchange Act of 1934, as amended (the “Exchange Act”). When used in this Quarterly Report on Form 10-Q, the words “could,” “believe,” “anticipate,” “intend,” “estimate,” “expect,” “may,” “continue,” “predict,” “potential,” “project,” “plan,” “will,” and similar expressions are intended to identify forward-looking statements, although not all forward-looking statements contain such identifying words. 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.

27
Table of Contents

Forward‑looking statements include statements related to, among other things:
•
the Company's business strategies;
•
reserves estimates;
•
estimated sales volumes;
•
amount and allocation of forecasted capital expenditures and plans for funding capital expenditures and operating expenses;
•
ability to modify future capital expenditures;
•
anticipated costs;
•
compliance with debt covenants;
•
ability to fund and satisfy obligations related to ongoing operations;
•
compliance with government regulations, including environmental, health, and safety regulations and liabilities thereunder;
•
adequacy of gathering systems and continuous improvement of such gathering systems;
•
impact from the lack of available gathering systems and processing facilities in certain areas;
•
impact of effectiveness of vapor control systems at central tank batteries;
•
natural gas, oil, and natural gas liquid prices and factors affecting the volatility of such prices;
•
impact of lower commodity prices;
•
sufficiency of impairments;
•
the ability to use derivative instruments to manage commodity price risk and ability to use such instruments in the future;
•
our drilling inventory and drilling intentions;
•
impact of potentially disruptive technologies;
•
our estimated revenues and losses;
•
the timing and success of specific projects;
•
our implementation of standard and long reach laterals in the Wattenberg Field;
•
our use of multi-well pads to develop the Niobrara and Codell formations;
•
intention to continue to optimize enhanced completion techniques and well design changes;
•
stated working interest percentages;
•
management and technical team;
•
outcomes and effects of litigation, claims, and disputes;
•
primary sources of future production growth;
•
full delineation of the Niobrara B, C and Codell benches in our legacy acreage, French Lake, and northern acreage;
•
our ability to replace oil and natural gas reserves;
•
our ability to convert PUDs to producing properties within five years of their initial proved booking;

28
Table of Contents

•
impact of recently issued accounting pronouncements;
•
impact of the loss a single customer or any purchaser of our products;
•
timing and ability to meet certain volume commitments related to purchase and transportation agreements;
•
the impact of customary royalty interests, overriding royalty interests, obligations incident to operating agreements, liens for current taxes, and other industry-related constraints;
•
our financial position;
•
our cash flow and liquidity;
•
the adequacy of our insurance; and
•
other statements concerning our operations, economic performance, and financial condition.
We have based these forward-looking statements on certain assumptions and analyses we have made in light of our experience and our perception of historical trends, current conditions, and expected future developments as well as other factors we believe are appropriate under the circumstances. They can be affected by inaccurate assumptions or by known or unknown risks and uncertainties. Many such factors will be important in determining actual future results. The actual results or developments anticipated by these forward-looking statements are subject to a number of risks and uncertainties, many of which are beyond our control, and may not be realized or, even if substantially realized, may not have the expected consequences. Actual results could differ materially from those expressed or implied in the forward-looking statements. 
Factors that could cause actual results to differ materially include, but are not limited to, the following: 
•
the risk factors discussed in Part I, Item 1A of our Annual Report on Form 10-K for the year ended December 31, 2018 and in Part II, Item 1A of this report;
•
further declines or volatility in the prices we receive for our oil, natural gas liquids, and natural gas;
•
general economic conditions, whether internationally, nationally or in the regional and local market areas in which we do business;
•
ability of our customers to meet their obligations to us;
•
our access to capital;
•
our ability to generate sufficient cash flow from operations, borrowings, or other sources to enable us to fully develop our undeveloped acreage positions;
•
the presence or recoverability of estimated oil and natural gas reserves and the actual future sales volume rates and associated costs;
•
uncertainties associated with estimates of proved oil and gas reserves;
•
the possibility that the industry may be subject to future local, state, and federal regulatory or legislative actions (including additional taxes and changes in environmental regulation);
•
environmental risks;
•
seasonal weather conditions;
•
lease stipulations;
•
drilling and operating risks, including the risks associated with the employment of horizontal drilling and completion techniques;
•
our ability to acquire adequate supplies of water for drilling and completion operations;
•
availability of oilfield equipment, services, and personnel;
•
exploration and development risks;

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•
competition in the oil and natural gas industry;
•
management’s ability to execute our plans to meet our goals;
•
our ability to attract and retain key members of our senior management and key technical employees;
•
our ability to maintain effective internal controls;
•
access to adequate gathering systems and pipeline take-away capacity;
•
our ability to secure adequate processing capacity for natural gas we produce, to secure adequate transportation for oil, natural gas, and natural gas liquids we produce, and to sell the oil, natural gas, and natural gas liquids at market prices;
•
costs and other risks associated with perfecting title for mineral rights in some of our properties;
•
continued hostilities in the Middle East, South America, and other sustained military campaigns or acts of terrorism or sabotage; and
•
other economic, competitive, governmental, legislative, regulatory, geopolitical, and technological factors that may negatively impact our businesses, operations, or pricing.
All forward-looking statements speak only as of the date of this report. We disclaim any obligation to update or revise these statements unless required by law, and you should not place undue reliance on these forward-looking statements. Although we believe that our plans, intentions, and expectations reflected in or suggested by the forward-looking statements we make in this report are reasonable, we can give no assurance that these plans, intentions, or expectations will be achieved. We disclose important factors that could cause our actual results to differ materially from our expectations under Part II, Item 1A. Risk Factors and Part I, Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations and elsewhere in this report. These cautionary statements qualify all forward-looking statements attributable to us or persons acting on our behalf. 
Item 3.    Quantitative and Qualitative Disclosures About Market Risk.
Oil and Natural Gas Price Risk  
Our financial condition, results of operations and capital resources are highly dependent upon the prevailing market prices of oil and natural gas. These commodity prices are subject to wide fluctuations and market uncertainties due to a variety of factors that are beyond our control. Factors influencing oil and natural gas prices include the level of global demand for oil and natural gas, the global supply of oil and natural gas, the establishment of and compliance with production quotas by oil exporting countries, weather conditions which determine the demand for natural gas, the price and availability of alternative fuels, local and global politics, and overall economic conditions. It is impossible to predict future oil and natural gas prices with any degree of certainty. Sustained weakness in oil and natural gas prices may adversely affect our financial condition and results of operations, and may also reduce the amount of oil and natural gas reserves that we can produce economically. Any reduction in our oil and natural gas reserves, including reductions due to price fluctuations, can have an adverse effect on our ability to obtain capital for our exploration and development activities. Similarly, any improvements in oil and natural gas prices can have a favorable impact on our financial condition, results of operations, and capital resources.
Commodity Derivative Contracts
Our primary commodity risk management objective is to reduce volatility in our cash flows. We enter into derivative contracts for oil and natural gas using NYMEX futures or over-the-counter derivative financial instruments with only counterparties whom we believe are well-capitalized and have been approved by our Board of Directors. The types of derivative instruments that we have entered into include commodity price swaps, cashless collars, and puts to mitigate a portion of our exposure to fluctuations in commodity prices.
To the extent that we enter into derivative contracts, we may be prevented from realizing the full benefits of favorable price changes in the physical market. Likewise, depending on what type of derivative contracts we use, we may not be fully insulated from downward commodity price movements.
Presently, all of our derivative arrangements are concentrated with four counterparties, all of which are lenders under our Current Credit Facility. If these counterparties fail to perform their obligations, we may suffer financial loss.

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The result of oil market prices exceeding our swap prices or collar ceilings requires us to make payments on the settlement of our derivatives, if owed by us, generally up to 15 business days before we receive market price cash payments from our customers. This could have a material adverse effect on our cash flows for the period between derivative settlement and payment for revenues earned.
Please refer to the  Note 10 - Derivatives in Part I, Item 1 of this report for summary derivative activity tables.
Interest Rates
As of March 31, 2019 , and on the filing date of this report we had $65.0 million outstanding under our Current Credit Facility. Borrowings under our Current Credit Facility bear interest at a fluctuating rate that is tied to an adjusted Base Rate or London Interbank Offered Rate, at our option. Any increases in these interest rates can have an adverse impact on our results of operations and cash flow. As of March 31, 2019 , and through the filing date of this report, the Company was in compliance with all financial and non-financial covenants in its Current Credit Facility.
Counterparty and Customer Credit Risk  
In connection with our derivatives activity, we have exposure to financial institutions in the form of derivative transactions. Four lenders under our Current Credit Facility are currently counterparties on our derivative instruments currently in place and have investment grade credit ratings.
We are also subject to credit risk due to concentration of our oil and natural gas receivables with certain significant customers. The inability or failure of our significant customers to meet their obligations to us or their insolvency or liquidation may adversely affect our financial results. We review the credit rating, payment history, and financial resources of our customers, but we do not require our customers to post collateral.
Marketability of Our Production  
The marketability of our production depends in part upon the availability, proximity and capacity of third-party refineries, access to regional trucking, pipeline and rail infrastructure, natural gas gathering systems, and processing facilities. We deliver crude oil and natural gas produced through trucking services and pipelines that we do not own. The lack of availability or capacity on these systems and facilities could reduce the price offered for our production or result in the shut-in of producing wells or the delay or discontinuance of development plans for properties.
A portion of our production may also be interrupted, or shut in, from time to time for numerous other reasons, including as a result of accidents, adverse weather, field labor issues or strikes, or we might voluntarily curtail production in response to market conditions. If a substantial amount of our production is interrupted at the same time, it could adversely affect our cash flow.
Currently, there are no pipeline systems that service wells in French Lake. If neither we nor a third-party constructs the required pipeline system, we may not be able to fully test or develop our resources in French Lake.
There have not been material changes to the interest rate risk analysis or oil and gas price sensitivity analysis disclosed in our Annual Report on Form 10-K for the year ended December 31, 2018.
Item 4.    Controls and Procedures.
Evaluation of Disclosure Controls and Procedures  
Our management, with the participation of our principal executive officer and principal financial officer, evaluated the effectiveness of our disclosure controls and procedures as of March 31, 2019 . The term “disclosure controls and procedures,” as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act, means controls and other procedures of a company that are designed to ensure that information required to be disclosed by a company in the reports that it files or submits under the Exchange Act is recorded, processed, summarized, and reported, within the time periods specified in SEC rules and forms. Disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed by a company in the reports that it files or submits under the Exchange Act is accumulated and communicated to the company’s management, including its principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure. Based on the evaluation of our disclosure controls and procedures as of March 31, 2019 , our principal executive officer and principal financial officer concluded that, as of such date, our disclosure controls and procedures were effective at the reasonable assurance level. 

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Management recognizes that any controls and procedures, no matter how well designed and operated, can provide only reasonable assurance of achieving their objectives, and management necessarily applies its judgment in evaluating the cost-benefit relationship of possible controls and procedures. To assist management, we have established an internal audit function to verify and monitor our internal controls and procedures. The Company’s internal control system is supported by written policies and procedures, contains self-monitoring mechanisms and is audited by the internal audit function. Appropriate actions are taken by management to correct deficiencies as they are identified.
Changes in Internal Control over Financial Reporting  
There were no changes in our internal control over financial reporting identified in management’s evaluation pursuant to Rules 13a-15(d) or 15d-15(d) of the Exchange Act during the quarter ended March 31, 2019 that materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
PART II - OTHER INFORMATION
 
Item 1.   Legal Proceedings.
From time to time, we are subject to legal proceedings and claims that arise in the ordinary course of business. Like other oil and gas producers and marketers, our operations are subject to extensive and rapidly changing federal and state environmental, health, and safety and other laws and regulations governing air emissions, wastewater discharges, and solid and hazardous waste management activities. As of the date of this filing, there are no material pending or overtly threatened legal actions against us of which we are aware.    
In February 2019, the Company was sent a notice of intent to sue (“NOI”) letter by WildEarth Guardians (“WEG”), an environmental non-governmental organization, alleging failure to obtain required permits under the federal Clean Air Act before constructing and operating well production facilities in the ozone non-attainment area around the Denver Metropolitan and North Front Range of Colorado, among other things. The Company is one of seven operators in the Wattenberg Field to receive such an NOI letter from WEG, and these letters appear to challenge long-established federal and state regulations and policies for permitting the construction and initial operation of upstream oil and gas production facilities in Colorado and elsewhere under the Clean Air Act and state counterpart statutes.
On May 3, 2019, WEG filed a lawsuit against the Company and the other six operators who received the NOI, alleging claims consistent with those contained in the NOI letters. Because the allegations made in the lawsuit are based on novel and unprecedented interpretations of complex federal and state air quality laws and regulations, it is not possible for the Company to determine at this time whether the allegations have merit, but the Company will vigorously defend against such allegations, and will coordinate as much as possible with state and federal permitting authorities to maintain the validity of its current and future air permits for such facilities.
There have been no other material changes to our legal proceedings from those described in our Annual Report on Form 10-K for the year ended December 31, 2018.
Item 1A. Risk Factors.
Our business faces many risks. Any of the risk factors discussed in this report or our other SEC filings could have a material impact on our business, financial position, or results of operations. Additional risks and uncertainties not presently known to us or that we currently believe to be immaterial may also impair our business operation. For a discussion of our potential risks and uncertainties, see the risk factors in Part I, Item 1A in our Annual Report on Form 10-K for the year ended December 31, 2018, together with other information in this report and other reports and materials we file with the SEC. We have identified these risk factors as important factors that could cause our actual results to differ materially from those contained in any written or oral forward-looking statements made by us or on our behalf.
As a Colorado-only oil and gas operator, we face a disproportionate risk associated with increasing activism and legislative and regulatory efforts which may serve to curtail oil and gas exploration and development activities in Colorado.

Opposition toward oil and gas drilling and development activity in Colorado has both increased and become more effective in recent years. On April 16, 2019, new legislation became effective in Colorado, which substantially changes the state’s regulation of oil and gas exploration and production activities, and applies immediately to all pending permit applications. The new law changes the COGCC mission from “fostering” responsible and balanced development to “regulating” public health and the environment. The required composition of the COGCC was also changed to remove two seats for oil and gas industry experts and add experts on wildlife/environmental protection and public health. The state’s statutory pooling provisions were changed by the new law to require that an applicant own, or obtain the consent of, at least

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45% of the applicable working or mineral interest, whereas previously the consent of only one mineral interest owner was required.
Among the most significant changes under the legislation was the provision of local government control over facility siting and surface impacts associated with oil and gas development. Whether an applicable local government determines to implement regulatory changes is optional, but if changes are adopted, the resulting regulations may be stricter than state requirements. Further, local governments may now inspect oil and gas operations and impose fines for leaks, spills, and emissions.
The legislation mandates COGCC rulemaking on environmental protection, facility siting, cumulative impacts, flowlines, wells that are inactive, temporarily abandoned, or shut-in, financial assurance, wellbore integrity, and application fees. Pending the completion of this initial rulemaking, the COGCC may delay acting on selected permit applications. Although the Company’s operations are not located near affected municipalities and may not ultimately be significantly impacted by select aspects of the new legislation and resulting COGCC rules, such permitting delays could substantially curtail the Company’s near-term pace of new oil and gas development.
Additionally, the new legislation requires the state’s AQCC to undertake rulemaking efforts to minimize methane emissions and emissions of other hydrocarbons, volatile organic compounds and nitrogen oxides associated with certain oil and gas facilities. The AQCC may also adopt more stringent standards for leak detection and repair inspection frequency, pipeline and compressor station inspection and maintenance frequencies, installation of continuous emission monitoring equipment at certain oil and gas facilities, and reduced emissions from pneumatic devices. The legislation also grants the AQCC regulatory authority over a broad range of oil and gas facilities during pre-production activities, drilling and completion.
Rules adopted by the COGCC and AQCC pursuant to the new legislation may significantly increase the Company’s operating costs, and have a material adverse effect on our business, financial condition, and results of operations.
Additionally, anti-development activists succeeded in adding a measure to the November 6, 2018 ballot in Colorado, which sought to require a minimum 2,500 foot setback from occupied structures and vulnerable areas for all new oil and gas development on non-federal land. While this initiative was ultimately unsuccessful, had it been successful, it may have resulted in dramatically reducing the area of future oil and gas development in Colorado. Such anti-development efforts are likely to continue in the future, which could result in dramatically reducing the area of future oil and gas development in Colorado or outright banning oil and gas development in Colorado. These efforts could have a material adverse effect on our business, financial condition, and results of operations.
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, 2019 .
  Issuer purchases of equity securities .  The following table contains information about acquisitions of our equity securities during the three month period ended March 31, 2019 :
 
 
 
 
 
 
 
Maximum 
 
 
 
 
 
Total Number of 
 
Number of
 
Total
 
 
 
Shares
 
Shares that May 
 
Number of
 
Average Price
 
Purchased as Part of
 
Be Purchased
 
Shares
 
Paid per
 
Publicly Announced
 
Under Plans or 
 
Purchased (1)
 
Share
 
Plans or Programs
 
Programs
January 1, 2019 - January 31, 2019
6,010

 
$
23.60

 
—

 
—

February 1, 2019 - February 28, 2019
26

 
$
22.42

 
—

 
—

March 1, 2019 - March 31, 2019
—

 
$
—

 
—

 
—

Total
6,036

 
$
23.42

 
—

 
—

____________________________________________________________________________
(1)
Represents shares that employees surrendered back to us that equaled in value the amount of taxes required for payroll tax withholding obligations upon the vesting of equity awards under the 2017 LTIP. These repurchases were not part of a publicly announced plan or program to repurchase shares of our common stock, nor do we have a publicly announced plan or program to repurchase shares of our common stock.
Our Current Credit Facility provides for restrictions on the payment of dividends.

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Item 3. Defaults Upon Senior Securities.
None
Item 4. Mine Safety Disclosures.
Not applicable.
Item 5. Other Information.
None
Item 6. Exhibits.
Exhibit
No.
    
Description of Exhibit
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
101.INS†
 
XBRL Instance Document
 
 
 
101.SCH†
 
XBRL Taxonomy Extension Schema
 
 
 
101.CAL†
 
XBRL Taxonomy Extension Calculation Linkbase
 
 
 
101.DEF†
 
XBRL Taxonomy Extension Definition Linkbase
 
 
 
101.LAB†
 
XBRL Taxonomy Extension Label Linkbase
 
 
 
101.PRE†
 
XBRL Taxonomy Extension Presentation Linkbase
†                 Filed or furnished herewith


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SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
 
 
 
 
BONANZA CREEK ENERGY, INC.
 
 
 
 
Date:
May 8, 2019
    
By:
/s/ Eric T. Greager
 
 
 
 
Eric T. Greager
 
 
 
 
President and Chief Executive Officer
 
 
 
 
(principal executive officer)
 
 
 
 
 
 
 
 
 
 
 
 
 
By:
/s/ Brant DeMuth
 
 
 
 
Brant DeMuth
 
 
 
 
Executive Vice President and Chief Financial Officer
 
 
 
 
(principal financial officer)
 
 
 
 
 
 
 
 
 
 
 
 
 
By:
/s/ Sandi K. Garbiso
 
 
 
 
Sandi K. Garbiso
 
 
 
 
Vice President and Chief Accounting Officer
 
 
 
 
(principal accounting officer)


35


Exhibit 10.1    


PERFORMANCE STOCK UNIT AGREEMENT
THIS PERFORMANCE STOCK UNIT AGREEMENT (this “ Agreement ”) is entered into as of the Grant Date (as defined below), by and between Grantee (as defined below) and Bonanza Creek Energy, Inc., a Delaware corporation (the “ Company ”).
WHEREAS, the Company maintains the Bonanza Creek Energy, Inc. 2017 Long Term Incentive Plan (the “ Plan ”), which is incorporated into and forms a part of this Agreement, and Grantee has been selected by the board of directors of the Company (the “ Board ”) or the compensation committee of the Board (the “ Committee ”) or any authorized delegate to receive an Award of Stock Units (the “ Award ”) under the Plan and as set forth in this Agreement.
NOW, THEREFORE, IT IS AGREED, by and between the Company and Grantee, as follows:
1. Definitions . The following terms used in this Agreement shall have the meanings set forth in this Section 1:
a)
“ Cause ” has the meaning set forth in the CIC Severance Plan.
b)
“ CIC Effective Date ” has the meaning set forth in the CIC Severance Plan.
c)
“ CIC Severance Plan ” means the Bonanza Creek Energy, Inc. Fifth Amended and Restated Executive Change in Control and Severance Plan, as the same may be amended from time to time.
d)
“ Date of Termination ” has the meaning set forth in the CIC Severance Plan.
e)
“ Designated Beneficiary ” means the beneficiary or beneficiaries designated by Grantee in a writing filed with the Company in the form attached hereto as Exhibit A .
f)
“ Disability ” or “ Disabled ” has the meaning set forth in the CIC Severance Plan.
g)
“ Eligible Individual ” has the meaning set forth in the CIC Severance Plan.
h)
“ Good Reason ” has the meaning set forth in the CIC Severance Plan.
i)
“ Grant Date ” means the date on which this Award was granted, as set forth in the Grant Notice.
j)
“ Grantee ” means the employee of the Company specified in the grant notice issued by the Company on or about the Grant Date (the “ Grant Notice ”).
k)
“ Performance Stock Units ” means a performance-based Stock Units (as defined in the Plan) granted under this Agreement and subject to the terms of this Agreement and the Plan.
l)
“ Release ” has the meaning set forth in the CIC Severance Plan.
m)
“ Service Agreement ” means any applicable agreement between the Company and Grantee regarding Grantee’s Service with the Company.

Capitalized terms used herein without definition have the meanings ascribed to such terms in the Plan. Except where the context clearly implies or indicates the contrary, a word, term, or phrase used in the Plan is similarly used in this Agreement.
2. Award . Grantee is hereby granted a Performance Stock Unit award covering the number of Performance Stock Units set forth in the Grant Notice.
3. Vesting . Except as set forth in Sections 4 and 5, the Performance Stock Units shall vest in accordance with the vesting schedule set forth in subsection (a), (b), and (c) of this Section 3. A Performance Stock Unit will vest only to the extent it time vests pursuant to Section 3(a) and performance vests pursuant to Section 3(b) or 3(c), as applicable. Any Performance Stock Units that do not time-vest will be forfeited for no consideration upon a Participant’s termination of employment, and any Performance Stock Units that do not performance-vest as of the conclusion of the Performance Period in accordance with Section 3(b) will be forfeited for no consideration at the conclusion of the Performance Period.
a)
Service Vesting Requirement . Except as otherwise provided herein, 100% of the Performance Stock Unit award granted hereunder shall time vest only if Grantee remains in continuous employment with the Company or any Subsidiary through the end of the Performance Period.




The “Performance Period” is the period beginning January 1, 2019 and ending December 31, 2021.
b)
TSR Performance Vesting Requirement . Fifty percent (50%) of the Performance Stock Units (the “ TSR PSUs ”) subject to this Award shall performance vest based upon the satisfaction of a performance vesting requirement based on the Relative Total Shareholder Return (“ TSR ”) of the Company as compared to the TSR of the Company’s eleven peer companies, as listed on Exhibit B (the “ Peer Group ”) with respect to Performance Period.

i.
Earning of Award . The extent to which the TSR PSUs will performance vest is based on both (A) the Company’s Absolute TSR Performance and (B) the Company’s Relative TSR Performance based on the following chart:
 
Absolute TSR Performance
 
<0%
0%
5%
10%
15%
20%
Relative TSR Performance
<25th Percentile
0%
0%
0%
0%
25%
50%
≥25th Percentile
0%
0%
0%
25%
50%
75%
≥50th Percentile
0%
0%
25%
50%
75%
100%
≥75th Percentile
0%
25%
50%
75%
100%
125%
≥90th Percentile
0%
50%
75%
100%
150%
200%

ii.
Calculation of TSR.
“ TSR ”    =
 
Change in Stock Price + Dividends Paid
Beginning Stock Price

 
A.
“ Beginning Stock Price ” shall mean the volume-weighted average price (“VWAP”) of a share of stock, as reported in transactions on the applicable stock exchange or market, during the 30 trading days immediately prior to the first trading day of the Performance Period;
B.
“ Ending Stock Price ” shall mean the VWAP of a share of stock, as reported in transactions on the applicable stock exchange or market, during the last 30 trading days of the Performance Period;
C.
“ Change in Stock Price ” shall equal the Ending Stock Price minus the Beginning Stock Price;
D.
“ Dividends Paid ” shall mean the total of all dividends paid on one share of stock during the Performance Period, provided that dividends shall be treated as though they are reinvested; and
E.
In all events, TSR shall be adjusted to give effect to any stock dividends, stock splits, reverse stock splits and similar transactions.

iii.
Calculation of Company’s TSR Percentile Ranking . The Company shall determine (i) the Company’s TSR for the Performance Period and (ii) the TSR for the Performance Period of each member of the Company’s Peer Group, as listed on Exhibit B . The Company’s TSR Percentile Ranking is the percentage of TSRs of the companies in the Peer Group that are lower than the Company’s TSR.
iv.
Changes in Peer Group . When calculating TSR for the Performance Period for the Company and the Peer Group, (A) subject to (B), below, the performance of a company




in the Peer Group will not be used in calculating the TSR of that member of the Peer Group if the company is not publicly traded ( i.e. , has no ticker symbol) at the end of the Performance Period; (B) the performance of the surviving entities will be used in the event there is a combination of any of the Peer Group companies during the measurement period; and (C) no new companies will be added to the Peer Group during the Performance Period (including a company that is not a Peer Group member which acquires a member of the Peer Group). Notwithstanding the foregoing provisions of this subsection (iv), the Committee may disregard any of these guidelines when evaluating changes in the membership of the Peer Group during the Performance Period in any particular situation, as it deems reasonable in the exercise of its discretion.
c)
ROCE Performance Vesting Requirement . The remaining 50% of the Performance Stock Units (the “ ROCE PSUs ”) will performance vest based upon the average annual return on capital employed (“ ROCE ”) over the Performance Period.
i.
Earning of Award . The extent to which the ROCE PSUs will performance-vest is based on the level at which the average annual ROCE target is achieved, as reflected in the following chart:
 
Average Annual ROCE Performance
Payout %
Below
13%
0%
Threshold
13%
50%
Target
16%
100%
Superior
19%
150%
Maximum
22%
200%

ii.
Calculation of ROCE for each year during the Performance Period.

“ ROCE ” of the applicable year during the Performance Period
   =
Recurring EBITDAX - DD&A
Employed Capital
 
 
A.
“ Recurring EBITDAX ” shall mean the Company’s earnings before interest and taxes, depreciation, depletion, amortization, exploration expenses, and other non-cash and non-recurring charges for the applicable year;
B.
“ DD&A ” shall mean the Company’s depreciation, depletion and amortization of the applicable year;
C.
“ Employed Capital ” shall mean (1) (x) the sum of the Company’s total assets as reported on the Company’s financial statements for the year immediately prior to the applicable year, plus the Company’s total assets as reported on the Company’s financial statements for the applicable year, (y) with such sum divided by two, minus (2) (x) the sum of the Company’s total current liabilities as reported on the Company’s financial statements for the year immediately prior to the applicable year, plus the Company’s total current liabilities as reported on the Company’s financial statements for the applicable year, (y) with such sum divided by two;
D.
In all events, ROCE shall be adjusted to give effect to any stock dividends, stock splits, reverse stock splits and similar transactions.





4. Termination of Services .
a)
Termination by Company for any reason other than Cause or by Grantee for Good Reason . Except as may otherwise be provided in any applicable Service Agreement, if the Grantee’s employment is terminated by the Company for any reason other than Cause or by Grantee for Good Reason, a pro-rata portion of the Performance Stock Units shall vest as of such Date of Termination, subject to Grantee’s execution and non-revocation of a Release within 60 days of Grantee’s Date of Termination. Such pro rata portion shall be equal to (i) the number of Performance Stock Units set forth in the Grant Notice ( i.e., the number of Performance Stock Units that would be paid out at the target performance level) multiplied by (ii) a fraction, the numerator of which is the number of days of the Performance Period the Grantee remained an employee with the Company and the denominator of which is the number of days in the Performance Period. All Performance Stock Units that remain unvested following the pro-rata vesting in accordance with this Section 4(a) will be automatically forfeited upon such Date of Termination.
b)
Termination by the Company for Cause; resignation by the Grantee not for Good Reason . Except as may otherwise be provided in any applicable Service Agreement, if the Grantee’s employment is terminated by the Company for Cause or due to a resignation by the Grantee for any reason other than Good Reason, Grantee shall forfeit any Performance Stock Units that have not fully vested in accordance with Section 3 as of the Date of Termination. All Performance Stock Units that are not earned based on performance during the Performance Period will be automatically forfeited as of the end of such Performance Period.

5. Change in Control . In the event of a Change in Control, if the Award is (a) continued or assumed or (b) substituted or replaced with an award with respect to cash or shares of the acquirer in such Change in Control, in each case, with substantially equivalent terms and value as the Award; provided that the Committee, in its discretion, may choose to revise or eliminate any performance-based vesting conditions as it deems appropriate (as applicable, “ Assumed ”), on the CIC Effective Date, and Grantee subsequently incurs a termination of employment covered by Section 5(d) of the CIC Severance Plan (without regard to whether Grantee is an Eligible Individual under the CIC Severance Plan), any unvested Performance Stock Units shall vest in full at the target performance level as of Grantee’s Date of Termination, subject to Grantee’s execution and non-revocation of a Release within 60 days of Grantee’s Date of Termination. If the Award is not Assumed on the CIC Effective Date, any unvested Performance Stock Units shall vest in full at the target performance level on the CIC Effective Date and no further benefit or payment shall be provided in respect thereof.

6. Payment . Payment in respect of vested Performance Stock Units shall be made by the Company as soon as administratively practicable (and in no event later than 74 days) after the applicable vesting date. The Company shall settle vested Performance Stock Units by issuing Grantee a number of shares of Stock equal to the number of vested Performance Stock Units.

7. Withholding .
a)
Any income taxes, FICA, state disability insurance or other similar payroll and withholding taxes (“ Withholding Obligation ”) arising with respect to the Performance Stock Units are the sole responsibility of Grantee. Any Withholding Obligation that arises as a result of the payment of cash amounts pursuant to the Dividend Equivalent Right set forth in Section 9 below shall be withheld by the Company in cash from the amounts paid. Any Withholding Obligation that arises as a result of the settlement of vested Performance Stock Units through granting of Stock pursuant to Section 6 above shall be settled pursuant to Sections 7(b) or 7(c) below.
b)
By accepting this Agreement, Grantee hereby elects, effective on the Grant Date, to sell shares of Stock held by Grantee in an amount and at such time as is determined in accordance with this Section 7(b), and to allow the Agent, as defined below, to remit the cash proceeds of such sales to the Company as more specifically set forth below (a “ Sell to Cover ”) to permit Grantee to satisfy the Withholding Obligation to the extent the Withholding Obligation is not otherwise




satisfied pursuant to the provisions of Section 7(c) below and further acknowledges and agrees to the following provisions:
i.
Grantee hereby irrevocably appoints the Company’s designated broker E*TRADE Securities LLC, or such other broker as the Company may select, as Grantee’s agent (the “ Agent ”), and authorizes and directs the Agent to:
1.
Sell on the open market at the then prevailing market price(s), on Grantee’s behalf, as soon as practicable on or after the delivery of Stock in settlement of vested Performance Stock Units, the number (rounded up to the next whole number) of shares of Stock sufficient to generate proceeds to cover (A) the satisfaction of the Withholding Obligation arising from the settlement of the vested Performance Stock Units to the extent not otherwise satisfied pursuant to Section 7(c) and (B) all applicable fees and commissions due to, or required to be collected by, the Agent with respect thereto;
2.
Remit directly to the Company the proceeds necessary to satisfy the Withholding Obligation;
3.
Retain the amount required to cover all applicable fees and commissions due to, or required to be collected by, the Agent, relating directly to the sale; and
4.
Deposit any remaining funds in Grantee’s account.
ii.
Grantee acknowledges that Grantee’s election to Sell to Cover and the corresponding authorization and instruction to the Agent set forth in Section 7(b) is intended to comply with the requirements of Rule 10b5-1(c)(1) under the Exchange Act, and to be interpreted to comply with the requirements of Rule 10b5-1(c) under the Exchange Act (Grantee’s election to Sell to Cover and the provisions of Section 7(b), collectively, the “ 10b5-1 Plan ”). Grantee acknowledges that by accepting this Award, he or she is adopting the 10b5-1 Plan to permit Grantee to satisfy the Withholding Obligation. Grantee hereby authorizes the Company and the Agent to cooperate and communicate with one another to determine the number of shares of Stock that must be sold pursuant to Section 7(b) to satisfy the Withholding Obligation.
iii.
Grantee acknowledges that the Agent is under no obligation to arrange for the sale of Stock at any particular price under this 10b5-1 Plan and that the Agent may effect sales as provided in this 10b5-1 Plan in one or more sales and that the average price for executions resulting from bunched orders may be assigned to Grantee’s account. In addition, Grantee acknowledges that it may not be possible to sell shares of Stock as provided for in this 10b5-1 Plan and in the event of the Agent’s inability to sell shares of Stock, Grantee will continue to be responsible for the Withholding Obligation.
iv.
Grantee hereby agrees to execute and deliver to the Agent any other agreements or documents as the Agent reasonably deems necessary or appropriate to carry out the purposes and intent of this 10b5-1 Plan. The Agent is a third-party beneficiary of Section 7(b) and the terms of this 10b5-1 Plan.
v.
Grantee’s election to Sell to Cover and to enter into this 10b5-1 Plan is irrevocable. This 10b5-1 Plan shall terminate not later than the date on which the Withholding Obligation arising from the payment of the vested Performance Stock Units is satisfied.
c)
Alternatively, or in addition to or in combination with the Sell to Cover provided for under Section 7(b), if authorized by the Committee, Grantee may satisfy the Withholding Obligation through Grantee surrendering shares of Stock to which Grantee is otherwise entitled to under the Plan with an aggregate fair market value that is not more than the maximum statutory withholding rates for federal and state tax purposes, including payroll taxes, that are applicable to such taxable income).

8. No Stockholder Rights . Grantee shall have no voting, dividend, or other stockholder rights in respect of the Performance Stock Units granted hereunder. Upon the issuance of shares of Stock as payment under this Agreement, Grantee shall have all of the rights of a stockholder with respect to such shares of Stock as of the date Grantee becomes the record owner of such shares.





9. Dividend Equivalent Right . Grantee shall be entitled to a Dividend Equivalent Right entitling Grantee, with respect to each Performance Stock Unit, to receive a cash payment based on the regular cash dividends that would have been paid on a share of Stock during the period between the Grant Date of the Performance Stock Units and the date the Performance Stock Units are paid pursuant to Section 6. All amounts payable as a result of such Dividend Equivalent Right shall be accumulated and paid to Grantee in cash on the date that payment is made in respect of the related Performance Stock Units in accordance with Section 6, above. For the sake of clarity, no Dividend Equivalent Rights shall be paid in respect of PSUs that are forfeited.

10. Heirs and Successors . This Agreement shall be binding upon, and inure to the benefit of, the Company and its successors and assigns, and upon any person acquiring, whether by merger, consolidation, purchase of assets or otherwise, all or substantially all of the Company’s assets and business. If any rights of Grantee or benefits distributable to Grantee under this Agreement have not been exercised or distributed, respectively, at the time of Grantee’s death, such rights shall be exercisable by the Designated Beneficiary, and such benefits shall be distributed to the Designated Beneficiary, in accordance with the provisions of this Agreement and the Plan. If a deceased Grantee fails to designate a beneficiary, or if the Designated Beneficiary does not survive Grantee, any rights that would have been exercisable by Grantee and any benefits distributable to Grantee shall be exercised by or distributed to the legal representative of the estate of Grantee. If a deceased Grantee designates a beneficiary and the Designated Beneficiary survives Grantee but dies before the Designated Beneficiary’s exercise of all rights under this Agreement or before the complete distribution of benefits to the Designated Beneficiary under this Agreement, then any rights that would have been exercisable by the Designated Beneficiary shall be exercised by the legal representative of the estate of the Designated Beneficiary, and any benefits distributable to the Designated Beneficiary shall be distributed to the legal representative of the estate of the Designated Beneficiary.

11. Administration . The authority to manage and control the operation and administration of this Agreement shall be vested in the Board or the Committee, and the Board or the Committee shall have all powers with respect to this Agreement as it has with respect to the Plan. Any interpretation of the Agreement by the Board or the Committee and any decision made by it with respect to the Agreement is final and binding on all persons.

12. Plan Governs . Notwithstanding anything in this Agreement to the contrary, the terms of this Agreement shall be subject to the terms of the Plan, a copy of which may be obtained by Grantee from the office of the Secretary of the Company, and this Agreement is subject to all interpretations, amendments, rules and regulations promulgated by the Board or the Committee from time to time pursuant to the Plan. For clarity, if Grantee participates in the CIC Severance Plan, nothing in this Agreement is intended to supersede any provisions of the CIC Severance Plan, including without limitation the definitions of “Cause,” Disability” and “Good Reason” therein, and in the event of any conflict between this Agreement and the CIC Severance Plan, the provisions of the CIC Severance Plan shall control.
13. Fractional Shares . In lieu of issuing a fraction of a share of Stock resulting from an adjustment of the Award pursuant to Section 17.4 of the Plan or otherwise, the Company will be entitled to pay to Grantee an amount in cash equal to the fair market value of such fractional share.

14. Not An Employment Contract . The Award will not confer on Grantee any right with respect to continuance of employment or other service with the Company or any Subsidiary, nor will it interfere in any way with any right the Company or any Subsidiary would otherwise have to terminate or modify the terms of such Grantee’s Service at any time.

15. Notices . Any written notices provided for in this Agreement or the Plan shall be in writing and shall be deemed sufficiently given if either hand delivered or if sent by fax or overnight courier, or by postage paid first class mail. Notices sent by mail shall be deemed received three business days after mailing but in no event later than the date of actual receipt. Notices shall be directed, if to Grantee, at Grantee’s address indicated by the Company’s records, or if to the Company, at the Company’s principal executive office.
16. Amendment . This Agreement may be amended in accordance with the provisions of the Plan, and may otherwise be amended by written agreement of Grantee and the Company without the consent of any other person.





17. 409A Savings Clause . All amounts payable hereunder are intended to comply with the requirements of Section 409A, and this Agreement shall be interpreted accordingly.

18. Electronic Acceptance . By logging into and accepting this Agreement through Grantee’s account with the Agent, Grantee (a) understands, represents, acknowledges and agrees to be bound by this Agreement as if Grantee had manually signed this Agreement, (b) agrees that Agent or its designee shall obtain and retain custody of the shares of Stock issuable upon settlement of vested Performance Stock Units until such time as all withholding obligations have been satisfied, (c) elects to conduct a Sell to Cover to satisfy the Withholding Obligation in accordance with Section 7(b) of the Agreement, (d) represents and warrants that (i) Grantee has carefully reviewed Section 7(b) of this Agreement, (ii) Grantee is not subject to any legal, regulatory or contractual restriction that would prevent the Agent from conducting sales and does not have, and will not attempt to exercise, authority, influence or control over any sales of Stock effected by the Agent and (iii) as of the date Grantee accepts this Agreement, Grantee is not aware or in possession of any material, nonpublic information with respect to the Company or its affiliates or any of their respective securities. In the event that Grantee does not accept this Agreement through the Agent’s online grant acceptance system within 90 days of the Grant Date, the Company shall have the option, but not the obligation, to cancel and revoke the Award represented by this Agreement, and the Award shall be forfeited by Grantee without any further consideration.
































    
Exhibit A





A-1

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

Primary Beneficiary
I hereby designate the following person or persons as primary Beneficiaries of my Account under the Plan payable in the event of my death.
Name:
 
Name:
Social Security Number:
 
Social Security Number:
Address:
 
Address:
Date of Birth:
 
Date of Birth:
Relationship to Participant:
 
Relationship to Participant:
Percentage:
 
Percentage:

The total of the percentages cannot exceed 100%. When more than one Beneficiary is designated, and no percentage is specified, payment will be made in equal shares to each surviving Beneficiary, or all to the last surviving Beneficiary.
Contingent Beneficiary
In the event that there is no living primary Beneficiary at my death, I hereby designate the following person or persons as contingent Beneficiaries of my Account:
Name:
 
Name:
Social Security Number:
 
Social Security Number:
Address:
 
Address:
Date of Birth:
 
Date of Birth:
Relationship to Participant:
 
Relationship to Participant:
Percentage:
 
Percentage:

The total of the percentages cannot exceed 100%. When more than one Beneficiary is designated, and no percentage is specified, payment will be made in equal shares to each surviving Beneficiary, or all to the last surviving Beneficiary.
Participant Signature
I reserve the right to revoke or change any Beneficiary designation. I hereby revoke all my prior designations (if any) of primary and contingent Beneficiaries.
Signature
DATE
 
 
Print Name
 

Please return this form to Human Resources when you have completed it.
Exhibit B





B-1

Peer Group

1.
Chaparral Energy, Inc.
2.
Extraction Oil & Gas, Inc.
3.
Callon Petroleum Company
4.
SRC Energy Inc.
5.
Carrizo Oil & Gas, Inc.
6.
Earthstone Energy, Inc.
7.
Halcon Resources Corporation
8.
SandRidge Energy, Inc.
9.
Eclipse Resources Corporation
10.
Abraxas Petroleum Corporation
11.
High Point Resources Corporation





Exhibit 31.1
CERTIFICATION OF THE CHIEF EXECUTIVE OFFICER PURSUANT TO RULE 13a‑ 14(a)
I, Eric T. Greager, certify that:
1. I have reviewed this Quarterly Report on Form 10‑Q for the period ended March 31, 2019 of Bonanza Creek Energy, Inc.;
2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a‑15(e) and 15d‑15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a‑15(f) and 15d‑15(f)) for the registrant and have:
a)
Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
b)
Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
c)
Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
d)
Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and
5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):
a)
All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
b)
Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.
Date:   May 8, 2019
 
/s/ Eric T. Greager
 
Eric T. Greager
 
President and Chief Executive Officer





Exhibit 31.2
CERTIFICATION OF THE PRINCIPAL FINANCIAL OFFICER PURSUANT TO RULE 13a‑ 14(a)
I, Brant DeMuth, certify that:
1. I have reviewed this Quarterly Report on Form 10‑Q for the period ended March 31, 2019 of Bonanza Creek Energy, Inc.;
2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a‑15(e) and 15d‑15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a‑15(f) and 15d‑15(f)) for the registrant and have:
a)
Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
b)
Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
c)
Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
d)
Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and
5.
The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):
a)
All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
b)
Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.
Date:   May 8, 2019
 
/s/ Brant DeMuth
 
Brant DeMuth
 
Executive Vice President and Chief Financial Officer (principal financial officer)









Exhibit 32.1
Certification of the Chief Executive Officer
Pursuant to 18 U.S.C. Section 1350,
As Adopted Pursuant to Section 906 of the Sarbanes‑Oxley Act of 2002
In connection with the Quarterly Report of Bonanza Creek Energy, Inc. (the “Company”) on Form 10-Q for the period ended March 31, 2019 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Eric T. Greager, President and Chief Executive Officer of the Company, certify, pursuant to 18 U.S.C. § 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that, to my knowledge:
(1) The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and
(2) The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.
Date:   May 8, 2019
 
/s/ Eric T. Greager
 
Eric T. Greager
 
President and Chief Executive Officer





Exhibit 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
In connection with the Quarterly Report of Bonanza Creek Energy, Inc. (the “Company”) on Form 10-Q for the period ended March 31, 2019 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Brant DeMuth, Executive Vice President and Chief Financial Officer of the Company, certify, pursuant to 18 U.S.C. § 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that to my knowledge:
(1) The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and
(2) The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.
Date: May 8, 2019
 
/s/ Brant DeMuth
 
Brant DeMuth
 
Executive Vice President and Chief Financial Officer (principal financial officer)