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Table of Contents

 
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549 
FORM 10-Q
 
QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
For the quarterly period ended June 30, 2019
or
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
 Commission File Number:  001-35371
 Bonanza Creek Energy, Inc.
(Exact name of registrant as specified in its charter) 
Delaware
 
61-1630631
(State or other jurisdiction of incorporation or organization)
 
(I.R.S. Employer Identification No.)
410 17th Street,
Suite 1400
 
 
Denver,
Colorado
 
80202
(Address of principal executive offices)
 
(Zip Code)
(720440-6100
(Registrant’s telephone number, including area code)
Securities registered pursuant to Section 12(b) of the Act:
Title of each class
Trading Symbol
Name of exchange on which registered
Common Stock, par value $0.01 per share
BCEI
New York Stock Exchange
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.   Yes ¨  No
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).   Yes  ¨  No
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer”, “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.
Large Accelerated Filer

Accelerated Filer
 
Non-accelerated Filer
(Do not check if a smaller reporting company)
 
 
 
Emerging growth company
Smaller reporting company
 
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act.
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).  Yes  No
Indicate by check mark whether the registrant has filed all documents and reports required to be filed by Sections 12, 13 or 15(d) of the Securities Exchange Act of 1934 subsequent to the distribution of securities under a plan confirmed by a court.  Yes   No

1

Table of Contents

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

2

Table of Contents

BONANZA CREEK ENERGY, INC.
INDEX
 
 
    
    
PAGE
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 


3

Table of Contents

PART I - FINANCIAL INFORMATION

Item 1.     Financial Statements.
BONANZA CREEK ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS (UNAUDITED)
(in thousands, except share amounts)
 
June 30, 2019
 
December 31, 2018
ASSETS
 

 
 

Current assets:
 

 
 

Cash and cash equivalents
$
9,149

 
$
12,916

Accounts receivable:
 

 
 

Oil and gas sales
40,341

 
31,799

Joint interest and other
23,946

 
47,577

Prepaid expenses and other
5,336

 
4,633

Inventory of oilfield equipment
2,946

 
3,478

Derivative assets (note 10)
11,116

 
34,408

Total current assets
92,834

 
134,811

Property and equipment (successful efforts method):
 

 
 

Proved properties
802,452

 
719,198

Less: accumulated depreciation, depletion and amortization
(86,265
)
 
(52,842
)
Total proved properties, net
716,187

 
666,356

Unproved properties
155,882

 
154,352

Wells in progress
133,364

 
93,617

Other property and equipment, net of accumulated depreciation of $2,853 in 2019 and $2,546 in 2018
3,490

 
3,649

Total property and equipment, net
1,008,923

 
917,974

Long-term derivative assets (note 10)
1,176

 
3,864

Right-of-use assets (note 3)
38,623

 

Other noncurrent assets
3,782

 
4,885

Total assets
$
1,145,338

 
$
1,061,534

LIABILITIES AND STOCKHOLDERS’ EQUITY
 

 
 

Current liabilities:
 

 
 

Accounts payable and accrued expenses (note 4)
$
45,087

 
$
79,390

Oil and gas revenue distribution payable
30,262

 
19,903

Current portion of lease liability (note 3)
10,593

 

Derivative liability (note 10)
2,066

 
183

Total current liabilities
88,008

 
99,476

 
 
 
 
Long-term liabilities:
 

 
 

Credit facility (note 5)
65,000

 
50,000

Lease liability (note 3)
28,792

 

Ad valorem taxes
34,370

 
18,740

Asset retirement obligations for oil and gas properties (note 9)
29,162

 
29,405

Total liabilities
245,332

 
197,621

 
 
 
 
Commitments and contingencies (note 6)

 

 
 
 
 
Stockholders’ equity:
 

 
 

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

 

Common stock, $.01 par value, 225,000,000 shares authorized, 20,632,999 and 20,543,940 issued and outstanding as of June 30, 2019 and December 31, 2018, respectively
4,285

 
4,286

Additional paid-in capital
698,526

 
696,461

Retained earnings
197,195

 
163,166

Total stockholders’ equity
900,006

 
863,913

Total liabilities and stockholders’ equity
$
1,145,338

 
$
1,061,534

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

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BONANZA CREEK ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME (UNAUDITED)
(in thousands, except per share amounts)
 
 
Three Months Ended June 30,
 
Six Months Ended June 30,
 
2019
 
2018
 
2019
 
2018
Operating net revenues:
 

 
 
 
 

 
 
Oil and gas sales
$
85,783

 
$
71,872

 
$
158,377

 
$
136,064

Operating expenses:
 

 
 
 
 
 
 
Lease operating expense
6,390

 
11,316

 
11,816

 
21,775

Gas plant and midstream operating expense
2,709

 
3,247

 
5,030

 
6,860

Gathering, transportation, and processing
4,331

 
1,660

 
8,353

 
3,998

Severance and ad valorem taxes
7,711

 
6,071

 
11,959

 
11,303

Exploration
408

 
221

 
505

 
250

Depreciation, depletion, and amortization
18,898

 
9,564

 
34,657

 
17,072

Abandonment and impairment of unproved properties
878

 
2,477

 
1,757

 
4,979

Unused commitments

 

 

 
21

General and administrative expense (including $1,768, $2,184, $3,148, and $3,192, respectively, of stock-based compensation)
9,803

 
9,917

 
20,081

 
19,451

Total operating expenses
51,128

 
44,473

 
94,158

 
85,709

Income from operations
34,655

 
27,399

 
64,219

 
50,355

Other income (expense):
 

 
 
 
 

 
 
Derivative gain (loss)
8,173

 
(22,012
)
 
(28,371
)
 
(30,754
)
Interest expense
(385
)
 
(805
)
 
(1,536
)
 
(1,162
)
Loss on sale of properties, net
(1,432
)
 

 
(306
)
 

Other income
11

 
277

 
23

 
290

Total other income (expense)
6,367

 
(22,540
)
 
(30,190
)
 
(31,626
)
Income from operations before taxes
41,022

 
4,859

 
34,029

 
18,729

Income tax benefit (expense)

 

 

 

Net income
$
41,022

 
$
4,859

 
$
34,029

 
$
18,729

 
 
 
 
 
 
 
 
Comprehensive income
$
41,022

 
$
4,859

 
$
34,029

 
$
18,729

 
 
 
 
 
 
 
 
Basic net income per common share
$
1.99

 
$
0.24

 
$
1.65

 
$
0.91

 
 
 
 
 
 
 
 
Diluted net income per common share
$
1.99

 
$
0.24

 
$
1.65

 
$
0.91




 
 
 
 
 
 
Basic weighted-average common shares outstanding
20,618

 
20,488

 
20,588

 
20,471




 
 
 
 
 
 
Diluted weighted-average common shares outstanding
20,664

 
20,603

 
20,630

 
20,538

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






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

 
$
4,286

 
$
696,461

 
$
163,166

 
$
863,913

Restricted common stock issued
 
20,687

 
 

 
 

 
 

 
 

Stock used for tax withholdings
 
(6,036
)
 
 

 
 
(153
)
 
 

 
 
(153
)
Stock-based compensation
 

 
 

 
 
1,380

 
 

 
 
1,380

Net loss
 

 
 

 
 

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

 
 
4,286

 
 
697,688

 
 
156,173

 
 
858,147

Restricted common stock issued
 
110,553

 
 

 
 

 
 

 
 

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

 
 
(931
)
Stock-based compensation
 

 
 

 
 
1,768

 
 

 
 
1,768

Net income
 

 
 

 
 

 
 
41,022

 
 
41,022

Balances, June 30, 2019
 
20,632,999

 
$
4,285

 
$
698,526

 
$
197,195

 
$
900,006

Balances, December 31, 2017
 
20,453,549

 
$
4,286

 
$
689,068

 
$
(5,020
)
 
$
688,334

Restricted common stock issued
 
107

 
 

 
 

 
 

 
 

Stock used for tax withholdings
 
(37
)
 
 

 
 

 
 

 
 

Stock-based compensation
 

 
 

 
 
1,008

 
 

 
 
1,008

Net income
 

 
 

 
 

 
 
13,870

 
 
13,870

Balances, March 31, 2018
 
20,453,619

 
 
4,286

 
 
690,076

 
 
8,850

 
 
703,212

Restricted common stock issued
 
78,002

 
 

 
 

 
 

 
 

Stock used for tax withholdings
 
(24,013
)
 
 

 
 
(794
)
 
 

 
 
(794
)
Exercise of stock options
 
27,191

 
 

 
 
968

 
 

 
 
968

Stock-based compensation
 

 
 

 
 
2,184

 
 

 
 
2,184

Net income
 

 
 

 
 

 
 
4,859

 
 
4,859

Balances, June 30, 2018
 
20,534,799

 
$
4,286

 
$
692,434

 
$
13,709

 
$
710,429

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



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BONANZA CREEK ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(UNAUDITED)
(in thousands)
 
Six months ended June 30,
 
2019
 
2018
Cash flows from operating activities:
 

 
 
Net income
$
34,029

 
$
18,729

Adjustments to reconcile net income to net cash provided by operating activities:
 
 
 
Depreciation, depletion, and amortization
34,657


17,072

Abandonment and impairment of unproved properties
1,757


4,979

Well abandonment costs and dry hole expense
62



Stock-based compensation
3,148


3,192

Amortization of deferred financing costs
248



Derivative loss
28,371


30,754

Derivative cash settlements
393


(11,622
)
Loss on sale of properties, net
306



Other
(901
)

172

Changes in current assets and liabilities:





Accounts receivable
15,089


(20,376
)
Prepaid expenses and other assets
(703
)

935

Accounts payable and accrued liabilities
(10,833
)

(889
)
Settlement of asset retirement obligations
(1,175
)

(797
)
Net cash provided by operating activities
104,448

 
42,149

Cash flows from investing activities:
 

 
 
Acquisition of oil and gas properties
(11,738
)

(1,295
)
Exploration and development of oil and gas properties
(111,398
)

(91,482
)
Proceeds from sale of oil and gas properties
1,153


20

Additions to property and equipment - non oil and gas
(148
)

(280
)
Net cash used in investing activities
(122,131
)
 
(93,037
)
Cash flows from financing activities:
 

 
 
Proceeds from Current Credit Facility
15,000



Proceeds from Prior Credit Facility


60,000

Proceeds from exercise of stock options


968

Payment of employee tax withholdings in exchange for the return of common stock
(1,083
)

(794
)
Net cash provided by financing activities
13,917

 
60,174

Net change in cash, cash equivalents, and restricted cash
(3,766
)
 
9,286

Cash, cash equivalents, and restricted cash:
 

 
 
Beginning of period
13,002

 
12,782

End of period
$
9,236

 
$
22,068

Supplemental cash flow disclosure:
 

 
 
Cash paid for interest, net of capitalization
$
1,190

 
$
906

Severance and ad valorem tax refund

$
352

 
$

Changes in working capital related to drilling expenditures
$
(8,763
)
 
$
1,909

     Cash paid for amounts included in the measurement of lease liabilities
$
4,366

 
$

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

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

NOTE 1 - ORGANIZATION AND BUSINESS
Bonanza Creek Energy, Inc. (“BCEI” or, together with our consolidated subsidiaries, the “Company”) is engaged primarily in acquiring, developing, extracting, and producing oil and gas properties. The Company’s assets and operations are concentrated in the rural portions of the Wattenberg Field in Colorado.
NOTE 2 - BASIS OF PRESENTATION
These unaudited condensed consolidated financial statements have been prepared in accordance with U.S. generally accepted accounting principles (“GAAP”) for interim financial statements and pursuant to the rules and regulations of the Securities and Exchange Commission. In the opinion of management, the accompanying unaudited condensed consolidated financial statements reflect all adjustments consisting of normal recurring adjustments as necessary for a fair presentation of our financial position and results of operations. Interim results of operations are not necessarily indicative of the results to be expected for the full fiscal year.
The financial information as of December 31, 2018, has been derived from the audited financial statements contained in our Annual Report on Form 10-K for the year ended December 31, 2018 (“2018 Form 10-K”), but does not include all disclosures, including notes required by GAAP. As such, this quarterly report should be read in conjunction with the consolidated financial statements and related notes included in our 2018 Form 10-K. The Company follows the same accounting principles for preparing quarterly and annual reports.
Principles of Consolidation
     The balance sheets include the accounts of the Company and its wholly owned subsidiaries, Bonanza Creek Energy Operating Company, LLC, Holmes Eastern Company, LLC, and Rocky Mountain Infrastructure, LLC. All significant intercompany accounts and transactions have been eliminated.
Use of Estimates
The preparation of the Company's condensed consolidated financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of oil and gas reserves, assets and liabilities, disclosure of contingent assets and liabilities at the date of the balance sheet, and the reported amounts of revenue and expenses during the reporting period. Actual results could differ from those estimates.
Revenue Recognition
Sales of oil, natural gas, and natural gas liquids (“NGLs”) are recognized when performance obligations are satisfied at the point control of the product is transferred to the customer. Virtually all of our contracts’ pricing provisions are tied to a market index, with certain adjustments based on, among other factors, whether a well delivers to a gathering or transmission line, quality of the oil or natural gas, and prevailing supply and demand conditions. As a result, the price of the oil, natural gas, and NGLs fluctuates to remain competitive with other available oil, natural gas, and NGLs supplies.
As further described in Note 6 - Commitments and Contingencies, one contract with NGL Crude Logistics, LLP (“NGL”, known as the “NGL agreement”) has an additional aspect of variable consideration related to the minimum volume commitments (“MVCs”) as specified in the agreement. On an on-going basis, the Company performs an analysis of expected risk adjusted production applicable to the NGL agreement based on approved production plans to determine if liquidated damages to NGL are probable. As of June 30, 2019, the Company believes that the volumes delivered to NGL will be in excess of the MVCs required then and for the upcoming approved production plan. As a result of this analysis, to date, no variable consideration related to potential liquidated damages has been considered in the transaction price for the NGL agreement.
Under our oil sales contracts we sell oil production at the wellhead, or other contractually agreed-upon delivery points, and collect an agreed-upon index price, net of pricing differentials. In this scenario, we recognize revenue when control transfers to the purchaser at the wellhead, or other contractually agreed-upon delivery point, at the net contracted price received.
Under our natural gas processing contracts, we deliver natural gas to an agreed-upon delivery point. The delivery points are specified within each contract, and the transfer of control varies between the inlet and outlet of the midstream processing facility. The midstream processing entity gathers and processes the natural gas and remits proceeds to the Company

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for the resulting sales of NGLs and residue gas. For the contracts where we maintain control through the outlet of the midstream processing facility, we recognize revenue on a gross basis, with gathering, transportation, and processing fees presented as an expense in our accompanying condensed consolidated statements of operations and comprehensive income (“statements of operations”). Alternatively, for those contracts where the Company relinquishes control at the inlet of the midstream processing facility, the Company recognizes natural gas and NGLs revenues based on the contracted amount of the proceeds received from the midstream processing entity and, as a result, we recognize revenue on a net basis.    
Under our product sales contracts, we invoice customers once our performance obligations have been satisfied, at which point payment is unconditional. Accordingly, our product sales contracts do not give rise to contract assets or liabilities under this guidance. At June 30, 2019 and December 31, 2018, our receivables from contracts with customers were $40.3 million and $31.8 million, respectively.
Revenue attributable to each of our identified revenue streams is disaggregated below (in thousands):
 
Three Months Ended June 30,
 
Six Months Ended June 30,
 
2019
 
2018
 
2019
 
2018
Operating Revenues:
 
 
 
 
 
 
 
   Crude oil sales
$
75,016

 
$
60,751

 
$
135,806

 
$
112,714

   Natural gas sales
6,507

 
$
4,938

 
13,964

 
11,159

   Natural gas liquids sales
4,260

 
6,183

 
8,607

 
12,191

Oil and gas sales

$
85,783

 
$
71,872

 
$
158,377

 
$
136,064


Restricted Cash
The following table provides a reconciliation of cash, cash equivalents, and restricted cash reported within the balance sheets, which sum to the total of such amounts shown in the accompanying condensed consolidated statements of cash flows (“statements of cash flows”) (in thousands):
 
As of June 30,
 
2019
 
2018
Cash and cash equivalents
$
9,149

 
$
21,989

Restricted cash included in other noncurrent assets
87

 
79

Total cash, cash equivalents, and restricted cash as shown in the statements of cash flows
$
9,236

 
$
22,068


Restricted cash consists of funds for road maintenance and repairs.
Accounting Pronouncements Recently Adopted and Issued
In February 2016, the FASB issued Update No. 2016-02 - Leases (ASC 842) to increase transparency and comparability among organizations by recognizing right-of-use assets and lease liabilities on the balance sheet and disclosing key information about leasing arrangements. Each lease that is recognized in the balance sheet will be classified as either finance or operating requiring certain quantitative and qualitative disclosures. Leases acquired to explore the development of oil and natural gas resources are not within the scope of this guidance. The new standard was adopted using the optional transition approach at the date of initial application on January 1, 2019. Please refer to Note 3 - Leases for additional disclosure.
In June 2016, the FASB issued Update No. 2016-13, Financial Instruments - Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments. The update changes the impairment model for most financial assets and certain other instruments, including trade and other receivables, and requires entities to use a new forward-looking expected loss model that will result in the earlier recognition of allowances for losses. The amended standard is effective for fiscal years beginning after December 15, 2019, including interim periods within those fiscal years, with early adoption permitted, and shall be applied using a modified retrospective approach resulting in a cumulative effect adjustment to retained earnings upon adoption. Historically, the Company's credit losses on oil and natural gas sales receivables and joint interest receivables have not been significant, and the Company does not believe the adoption of this standard will have a material impact on its consolidated financial statements.
In August 2018, the FASB issued Update No. 2018-13, Disclosure Framework - Changes to the Disclosure Requirements for Fair Value Measurement. The objective of this update is to improve the effectiveness of fair value

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measurement disclosures. This update is effective for annual periods beginning after December 15, 2019, and interim periods within those annual periods. The standard will only impact the form of the Company's disclosures.
There are no other accounting standards applicable to the Company that would have a material effect on the Company’s financial statements and disclosures that have been issued but not yet adopted by the Company as of June 30, 2019, and through the filing date of this report.

NOTE 3 - LEASES
On January 1, 2019, the Company adopted ASC 842 using the optional transition approach prescribed in Updated No 2018-11 - Lease (Topic 842), Targeted Improvements. Under this approach, results for reporting periods beginning January 1, 2019, are presented in accordance with ASC 842, while prior period amounts are reported in accordance with ASC 840 - Leases. The Company recognized $32.8 million and $33.6 million in right-of-use assets and lease liabilities, respectively, on January 1, 2019, representing minimum payment obligations associated with compressors, vehicles, office space, and other field and corporate equipment with contractual durations in excess of one year. There was no cumulative-effect adjustment to retained earnings upon adoption of the new standard.
ASC 842 provided certain practical expedients, of which the Company elected (i) to account for lease and non-lease components in its contracts as a single lease component for all asset classes, (ii) to adopt the land easement practical expedient, which allows the Company to apply ASC 842 prospectively to new or modified land easements beginning January 1, 2019, and (iii) to not apply the recognition requirements of ASC 842 to leases with a lease term of twelve months or less. The Company's leasing activities as a lessor are negligible.
During the three and six months ended June 30, 2019, the Company incurred $8.9 million and $10.1 million, respectively, in new right-of-use assets and lease liabilities. The Company’s right-of-use assets and lease liabilities are recognized at their discounted present value on the balance sheet at $38.6 million and $39.4 million as of June 30, 2019, respectively. All leases recognized on the Company's balance sheet are classified as operating leases, which include leases related to the asset classes reflected in the table below (in thousands):
 
 
Right-of-use Asset
 
Lease Liability
Field equipment(1)
$
34,712

$
34,712

Corporate leases
 
2,987

 
3,749

Vehicles
 
924

 
924

Total
$
38,623

$
39,385

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

The lease amounts disclosed are presented on a gross basis. A portion of these costs may have been or will be billed to other working interest owners, and the Company's net share of these costs once paid are included in proved properties, other property and equipment, lease operating expenses, or general and administrative expenses, as applicable.
The Company recognizes lease expense on a straight-line basis excluding short-term and variable lease payments, which are recognized as incurred. Short-term lease cost represents payments for leases with a lease term of one year or less, excluding leases with a term of one month or less. Short-term leases include drilling rigs and other equipment. Drilling rig contracts are structured based on an allotted number of wells to be drilled consecutively at a daily operating rate. Short-term drilling rig costs include a non-lease labor component, which is treated as a single lease component.
        
The following table summarizes the components of the Company's gross operating lease costs incurred during the three and six months ended June 30, 2019 (in thousands):
 
 
Three Months Ended June 30, 2019
 
Six Months Ended June 30, 2019
Operating lease cost(1)
$
2,686

$
5,036

Short-term lease cost
 
2,000

 
3,822

Variable lease cost(2)
 
109

 
129

Sublease income(3)
 
(87
)
 
(174
)
Total lease cost
$
4,708

$
8,813

____________________________

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(1) Includes office rent expense of $0.3 million and $0.5 million for the three and six months ended June 30, 2019, respectively.
(2) Variable lease cost represents differences between minimum lease obligations and actual costs incurred for certain leases that do not have fixed payments related to both lease and non-lease components. Such incremental costs include lease payment increases or decreases driven by market price fluctuations and leased asset maintenance costs.
(3) The Company subleased a portion of its office space for the remainder of the office lease term.

The Company does not have any leases with an implicit interest rate that can be readily determined. As a result, the Company used the incremental borrowing rate, based on the Current Credit Facility benchmark rate, adjusted for facility utilization and lease term, to calculate the respective discount rates. Please refer to Note 5 - Long-term Debt for additional information.
The Company's weighted-average lease term and discount rate used during the three and six months ended June 30, 2019 are as follows:
 
 
Three Months Ended June 30, 2019
 
Six Months Ended June 30, 2019
Weighted-average lease term (years)
 
3.8

 
3.8

Weighted-average discount rate
 
4.33
%
 
4.33
%

Minimum future commitments by year for the Company's long-term operating leases as of June 30, 2019 are presented in the table below. Such commitments are reflected at undiscounted values and are reconciled to the discounted present value recognized on the balance sheet as follows (in thousands):
 
 
Amount
Remainder of 2019
$
6,081

2020
 
11,831

2021
 
10,659

2022
 
8,911

2023
 
4,477

Thereafter
 
690

Total lease payments
 
42,649

Less: imputed interest
 
(3,264
)
Total lease liability
$
39,385


Future minimum lease payments related to the Company’s operating leases as of December 31, 2018 are presented below (in thousands):
 
 
Amount
2019
$
1,256

2020
 
1,351

2021
 
1,401

2022
 
234

2023
 

2024 and thereafter
 

Total
$
4,242



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NOTE 4 - ACCOUNTS PAYABLE AND ACCRUED EXPENSES
Accounts payable and accrued expenses contain the following (in thousands):
 
As of June 30, 2019
 
As of December 31, 2018
Accrued drilling and completion costs
$
24,839

 
$
33,602

Accounts payable trade
6,593

 
11,532

Accrued general and administrative expense
2,726

 
12,728

Accrued lease operating expense
2,700

 
2,183

Accrued interest
587

 
241

Accrued oil and gas hedging
45

 

Accrued production and ad valorem taxes and other
7,597

 
19,104

Total accounts payable and accrued expenses
$
45,087

 
$
79,390


NOTE 5 LONG-TERM DEBT 
Current Credit Facility
On December 7, 2018, the Company entered into a reserve-based revolving facility, as the borrower, with JPMorgan Chase Bank, N.A., as the administrative agent, and a syndicate of financial institutions, as lenders (the “Current Credit Facility”). The Current Credit Facility has an aggregate original commitment amount of $750.0 million, an initial borrowing base of $350.0 million, and matures on December 7, 2023. The Current Credit Facility borrowing base is redetermined on a semi-annual basis, with the most recent being concluded on May 16, 2019 resulting in an increase in the borrowing base to $375.0 million; however, the Company chose to hold the aggregate elected commitments at $350.0 million. The next scheduled redetermination is set to occur in November 2019.
Borrowings under the Current Credit Facility bear interest at a per annum rate equal to, at the option of the Company, either (i) a London InterBank Offered Rate (“LIBOR”), subject to a 0% LIBOR floor plus a margin of 1.75% to 2.75%, based on the utilization of the Current Credit Facility (the “Eurodollar Rate”) or (ii) a fluctuating interest rate per annum equal to the greatest of (a) the rate of interest publicly announced by JPMorgan Chase Bank, N.A. as its prime rate, (b) the rate of interest published by the Federal Reserve Bank of New York as the federal funds effective rate, (c) the rate of interest published by the Federal Reserve Bank of New York as the overnight bank funding rate, or (d) a LIBOR offered rate for a one-month interest period, subject to a 0% LIBOR floor plus a margin of 0.75% to 1.75%, based on the utilization of the Current Credit Facility (the “Reference Rate”). Interest on borrowings that bear interest at the Eurodollar Rate shall be payable on the last day of the applicable interest period selected by the Company, which shall be one, two, three, or six months, and interest on borrowings that bear interest at the Reference Rate shall be payable quarterly in arrears. The Company's Current Credit Facility approximates fair value as the applicable interest rates are floating.
The Current Credit Facility is guaranteed by all wholly-owned subsidiaries of the Company (each, a “Guarantor” and, together with the Company, the “Credit Parties”), and is secured by first priority security interests on substantially all assets of each Credit Party, subject to customary exceptions.
The Current Credit Facility contains customary representations and affirmative covenants. The Current Credit Facility also contains customary negative covenants, which, among other things, and subject to certain exceptions, include restrictions on (i) liens, (ii) indebtedness, guarantees and other obligations, (iii) restrictions in agreements on liens and distributions, (iv) mergers or consolidations, (v) asset sales, (vi) restricted payments, (vii) investments, (viii) affiliate transactions, (ix) change of business, (x) foreign operations or subsidiaries, (xi) name changes, (xii) use of proceeds, letters of credit, (xiii) gas imbalances, (xiv) hedging transactions, (xv) additional subsidiaries, (xvi) changes in fiscal year or fiscal quarter, (xvii) operating leases, (xviii) prepayments of certain debt and other obligations, (xix) sales or discounts of receivables, and (xx) dividend payments. The Credit Parties are subject to certain financial covenants under the Current Credit Facility, including, without limitation, tested on the last day of each fiscal quarter, (i) a maximum ratio of the Company’s consolidated indebtedness (subject to certain exclusions) to earnings before interest, income taxes, depreciation, depletion, and amortization, exploration expense, and other non-cash charges (“EBITDAX”) of 4.00 to 1.00 and (ii) a current ratio, as defined in the agreement, inclusive of the unused Commitments then available to be borrowed, to not be less than 1.00 to 1.00. The Company was in compliance with all covenants as of June 30, 2019, and through the filing date of this report.

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The Company had $65.0 million and $50.0 million outstanding on the Current Credit Facility as of June 30, 2019 and December 31, 2018, respectively. As of the date of filing, the Company had $80.0 million outstanding on its Current Credit Facility.
In connection with the Current Credit Facility, the Company capitalized a total of $2.5 million in deferred financing costs, of which $1.7 million and $0.5 million of the total post amortization net capitalized amounts are presented within other noncurrent assets and prepaid expenses and other line items, respectively, in the accompanying condensed consolidated balance sheets (“balance sheets”) as of June 30, 2019 and December 31, 2018, respectively.
Prior Credit Facility
Upon emergence from bankruptcy, the Company entered into a revolving credit facility, as the borrower, with KeyBank National Association, as the administrative agent, and certain lenders party thereto (the “Prior Credit Facility”). The borrowing base was $191.7 million and had a maturity date of March 31, 2021.
The Prior Credit Facility stated the Company's leverage ratio of indebtedness to EBITDAX was not to exceed 3.50 to 1.00, the minimum current ratio had to be 1.00 to 1.00, and the minimum interest coverage ratio of trailing twelve-month EBITDAX to trailing twelve-month interest expense had to be 2.50 to 1.00 as of the end of the respective fiscal quarter. During the period the Prior Credit Facility was outstanding, the Company was in compliance with all covenants.

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

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

NOTE 6 - COMMITMENTS AND CONTINGENCIES
Legal Proceedings 
From time to time, the Company is involved in various commercial and regulatory claims, litigation, and other legal proceedings that arise in the ordinary course of its business. The Company assesses these claims in an effort to determine the degree of probability and range of possible loss for potential accrual in its condensed consolidated financial statements. In accordance with GAAP, an accrual is recorded for a loss contingency when its occurrence is probable and damages can be reasonably estimated based on the most likely anticipated outcome or the minimum amount within a range of possible outcomes. Because legal proceedings are inherently unpredictable and unfavorable resolutions could occur, assessing contingencies is highly subjective and requires judgments about uncertain future events. When evaluating contingencies, the Company may be unable to provide a meaningful estimate due to a number of factors, including the procedural status of the matter in question, the presence of complex or novel legal theories, and/or the ongoing discovery and development of information important to the matters. The Company regularly reviews contingencies to determine the adequacy of its accruals and related disclosures. No claims have been made, nor is the Company aware of any material uninsured liability which the Company may have, as it relates to any environmental cleanup, restoration, or the violation of any rules or regulations. As of the filing date of this report, there were no material pending or overtly threatened legal actions against the Company of which it is aware.
As previously described in its 2018 Form 10-K, the Company and the Colorado Department of Public Health and Environment (“CDPHE”) agreed to a Compliance Order on Consent (the “COC”) resolving the matters addressed by a compliance advisory issued to the Company for certain storage tank facilities located in the Wattenberg Field with respect to applicable air quality regulations. The COC further set forth compliance requirements and criteria for continued operations. The Company adopted procedures and processes to address the monitoring, reporting, and control of air emissions. In order to be in compliance, the Company has incurred approximately $1.6 million from 2017 through June 30, 2019 and expects to incur an immaterial amount of maintenance during the remainder of 2019 through 2022. The COC can be terminated after four years with a showing of substantial compliance and CDPHE approval.
In February 2019, the Company was sent a notice of intent to sue (“NOI”) letter by WildEarth Guardians (“WEG”), an environmental non-governmental organization, alleging failure to obtain required permits under the federal Clean Air Act before constructing and operating well production facilities in the ozone non-attainment area around the Denver Metropolitan and North Front Range of Colorado, among other things. The Company is one of seven operators in the Wattenberg Field to receive such an NOI letter from WEG, and these letters appear to challenge long-established federal and state regulations and

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policies for permitting the construction and initial operation of upstream oil and gas production facilities in Colorado and elsewhere under the Clean Air Act and state counterpart statutes.
On May 3, 2019, WEG filed a lawsuit against the Company and the other six operators who received the NOI, alleging claims consistent with those contained in the NOI letters. Because the allegations made in the lawsuit are based on novel and unprecedented interpretations of complex federal and state air quality laws and regulations, it is not possible for the Company to determine at this time whether the allegations have merit, but the Company will vigorously defend against such allegations and will coordinate as much as possible with state and federal permitting authorities to maintain the validity of its current and future air permits for such facilities.
Commitments
The purchase agreement to deliver fixed determinable quantities of crude oil to NGL became effective on April 28, 2017. The NGL agreement includes defined volume commitments over an initial seven-year term. Under the terms of the NGL agreement, the Company will be required to make periodic deficiency payments for any shortfalls in delivering minimum gross volume commitments, which are set in six-month periods beginning in January 2018. During 2018, the average minimum gross volume commitment was approximately 10,100 barrels per day, and the minimum gross volume commitment increased by approximately 41% from 2018 to 2019 and will increase approximately 3% each year thereafter for the remainder of the contract, to a maximum of approximately 16,000 gross barrels per day. The aggregate financial commitment fee over the remaining term, based on the minimum gross volume commitment schedule (as defined in the agreement) and the applicable differential fee, is $88.5 million as of June 30, 2019. Upon notifying NGL at least twelve months prior to the expiration date of the NGL agreement, the Company may elect to extend the term of the NGL agreement for up to three additional years.
The annual minimum commitment payments under the NGL agreement for the next five years as of June 30, 2019 are presented below (in thousands):
 
 
NGL Gross Commitments(1)
2019
$
10,043

2020
 
22,487

2021
 
21,278

2022
 
21,790

2023
 
12,946

2024 and thereafter
 

Total
$
88,544

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

Since the commencement of the NGL agreement and through the remainder of term of the agreement, the Company has not and does not expect to incur any deficiency payments.
There have been no other material changes from the commitments disclosed in the notes to the Company’s consolidated financial statements included in our 2018 Form 10-K. Refer to Note 3 - Leases, for lease commitments.
NOTE 7 - STOCK-BASED COMPENSATION
2017 Long Term Incentive Plan
Upon emergence from bankruptcy, the Company adopted a new Long Term Incentive Plan (the “2017 LTIP”), as established by the pre-emergence Board of Directors, which allows for the issuance of restricted stock units (“RSUs”), performance stock units (“PSUs”), and options. Upon emergence from bankruptcy, the Company reserved 2,467,430 shares of the new common stock for issuance under the 2017 LTIP. See below for further discussion of awards granted under the 2017 LTIP.
Restricted Stock Units
The 2017 LTIP allows for the issuance of RSUs to members of the Board of Directors (the “Board”) and employees of the Company at the discretion of the Board. Each RSU represents one share of the Company's common stock to be released from restriction upon completion of the vesting period. The awards typically vest in one-third increments over three years. The

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RSUs are valued at the grant date share price and are recognized as general and administrative expense over the vesting period of the award.
During the six months ended June 30, 2019, the Company granted 251,000 RSUs with a fair value of $5.7 million. Total compensation expense recorded for RSUs, inclusive of grants to the members of the Board, for the three and six months ended June 30, 2019 was $1.3 million and $2.4 million, respectively. As of June 30, 2019, unrecognized compensation expense for RSUs was $13.4 million and will be amortized through 2023.
A summary of the status and activity of non-vested restricted stock units is presented below:
 
Restricted Stock Units
 
Weighted-
Average
Grant-Date
Fair Value    
Non-vested at beginning of year
480,835

 
$
30.83

Granted
251,000

 
$
22.76

Vested
(128,642
)
 
$
23.50

Forfeited
(5,090
)
 
$
33.22

Non-vested at end of quarter
598,103

 
$
26.99


Cash flows resulting from excess tax benefits are to be classified as part of cash flows from operating activities. Excess tax benefits are realized tax benefits from tax deductions for vested restricted stock in excess of the deferred tax asset attributable to stock compensation costs for such restricted stock. The Company recorded no excess tax benefits for the periods presented.
Performance Stock Units
The 2017 LTIP allows for the issuance of PSUs to employees at the sole discretion of the Board. The number of shares of the Company’s common stock that may be issued to settle PSUs range from zero to two times the number of PSUs awarded. The PSUs vest in their entirety at the end of the three-year performance period. The total number of PSUs granted is evenly split between two performance criterion. The first criterion is based on a comparison of the Company’s absolute and relative total shareholder return (“TSR”) for the performance period compared with the TSRs of a group of peer companies for the same performance period. The TSR for the Company and each of the peer companies is determined by dividing (A)(i) the volume-weighted average share price for the last 30 trading days of the performance period, minus (ii) the volume-weighted average share price for the 30 trading days preceding the beginning of the performance period, by (B) the volume-weighted average share price for the 30 trading days preceding the beginning of the performance period. The second criterion is based on the Company's average annual return on capital employed (“ROCE”) for each year during the three-year performance period. Compensation expense associated with PSUs is recognized as general and administrative expense over the performance period.
The fair value of the PSUs was measured at the grant date with a stochastic process method using a Brownian Motion simulation. A stochastic process is a mathematically defined equation that can create a series of outcomes over time. These outcomes are not deterministic in nature, which means that by iterating the equations multiple times, different results will be obtained for those iterations. In the case of the Company’s PSUs, the Company could not predict with certainty the path its stock price or the stock prices of its peers would take over the performance period. By using a stochastic simulation, the Company created multiple prospective stock pathways, statistically analyzed these simulations, and ultimately made inferences regarding the most likely path the stock price would take. As such, because future stock prices are stochastic, or probabilistic with some direction in nature, the stochastic method, specifically the Brownian Motion Model, was deemed an appropriate method by which to determine the fair value of the portion of the PSUs tied to the TSR. Significant assumptions used in this simulation include the Company’s expected volatility, risk-free interest rate based on U.S. Treasury yield curve rates with maturities consistent with the performance period, as well as the volatilities for each of the Company’s peers.
During the six months ended June 30, 2019, the Company granted 102,379 PSUs to certain officers with a fair value of $2.3 million. Total compensation expense recorded for PSUs for the three and six months ended June 30, 2019 was $0.3 million and $0.4 million, respectively. As of June 30, 2019, unrecognized compensation costs for PSUs was $3.0 million and will be amortized through 2021.
    

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A summary of the status and activity of performance stock units is presented below:
 
Performance Stock Units
 
Weighted-
Average
Grant-Date
Fair Value    
Non-vested at beginning of year(1)
53,689


$
29.92

Granted (1)
102,379


$
22.15

Vested(1)
(2,598
)

$
23.55

Forfeited(1)


$

Non-vested at end of quarter (1)
153,470

 
$
24.74

___________________________
(1)
The number of awards assumes that the associated performance condition is met at the target amount. The final number of shares of the Company’s common stock issued may vary depending on the performance multiplier, which ranges from zero to two, depending on the level of satisfaction of the performance condition.
Stock Options
The 2017 LTIP allows for the issuance of stock options to the Company's employees at the sole discretion of the Board of Directors. Options expire ten years from the grant date unless otherwise determined by the Board of Directors. Compensation expense on the stock options is recognized as general and administrative expense over the vesting period of the award.
There were no stock options granted during the six months ended June 30, 2019. Total expense recorded for stock options for the three and six months ended June 30, 2019 was $0.1 million and $0.3 million, respectively. As of June 30, 2019, unrecognized compensation cost for stock options was $0.5 million and will be amortized through 2020.
Stock options are valued using a Black-Scholes Model where expected volatility is based on an average historical volatility of a peer group selected by management over a period consistent with the expected life assumption on the grant date, the risk-free rate of return is based on the U.S. Treasury constant maturity yield on the grant date with a remaining term equal to the expected term of the awards, and the Company’s expected life of stock option awards is derived from the midpoint of the average vesting time and contractual term of the awards.
A summary of the status and activity of non-vested stock options is presented below:
 
Stock Options
 
Weighted-
Average
Exercise Price
 
Weighted-Average Remaining Contractual Term (in years)
 
Aggregate Intrinsic Value (in thousands)
Outstanding at beginning of year
132,809

 
$
34.36

 
6.7

 
$

Granted

 

 

 
$

Exercised

 

 

 
$

Forfeited
(27,018
)
 
$
34.36

 

 
$

Outstanding at end of quarter
105,791

 
$
34.36

 
7.8

 
$

Number of options outstanding and exercisable

70,524

 
$
34.36

 
7.8

 
$


NOTE 8 - FAIR VALUE MEASUREMENTS
The Company follows fair value measurement authoritative guidance, which defines fair value, establishes a framework for using fair value to measure assets and liabilities, and expands disclosures about fair value measurements. The authoritative accounting guidance defines fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. The statement establishes a hierarchy for inputs used in measuring fair value that maximizes the use of observable inputs and minimizes the use of unobservable inputs by requiring that the most observable inputs be used when available. The hierarchy is broken down into three levels based on the reliability of the inputs as follows:
Level 1: Quoted prices are available in active markets for identical assets or liabilities 
Level 2: Quoted prices in active markets for similar assets and liabilities, quoted prices for identical or similar instruments in markets that are not active, and model-derived valuations whose inputs are observable or whose significant value drivers are observable

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Level 3: Significant inputs to the valuation model are unobservable
The following tables present the Company's financial and non-financial assets and liabilities that were accounted for at fair value and their classification within the fair value hierarchy (in thousands):
 
As of June 30, 2019
 
Level 1
 
Level 2
 
Level 3
Derivative assets(1)
$

 
$
12,292

 
$

Derivative liabilities(1)
$

 
$
2,066

 
$

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

 
$
38,272

 
$

Derivative liabilities(1)
$

 
$
183

 
$

Asset retirement obligations(2)
$

 
$

 
$
1,490

____________________________
(1)
This represents a financial asset or liability that is measured at fair value on a recurring basis.
(2)
Represents the revision to estimates of the asset retirement obligation, which is a non-financial liability that is measured at fair value on a nonrecurring basis. Please refer to the Asset Retirement Obligation section below for additional discussion.
Derivatives
Fair value of all derivative instruments are estimated with industry-standard models that consider various assumptions, including quoted forward prices for commodities, time value of money, volatility factors and current market and contractual prices for the underlying instruments, as well as other relevant economic measures. All valuations were compared against counterparty statements to verify the reasonableness of the estimate. The Company’s commodity swaps and collars were validated by observable transactions for the same or similar commodity options using the NYMEX futures index, and were designated as Level 2 within the valuation hierarchy.
Asset Retirement Obligation
The Company utilizes the income valuation technique to determine the fair value of the asset retirement obligation liability at the point of inception by applying a credit-adjusted risk-free rate, which takes into account the Company’s credit risk, the time value of money, and the current economic state, to the undiscounted expected abandonment cash flows. Upon completion of wells, the Company records an asset retirement obligation at fair value using Level 3 assumptions. Given the unobservable nature of the inputs, the initial measurement of the asset retirement obligation liability is deemed to use Level 3 inputs. There were no asset retirement obligations measured at fair value as of June 30, 2019. The Company had $1.5 million of asset retirement obligations recorded at fair value as of December 31, 2018.
NOTE 9 - ASSET RETIREMENT OBLIGATIONS
The Company recognizes an estimated liability for future costs to abandon its oil and gas properties. The fair value of the asset retirement obligation is recorded as a liability when incurred, which is typically at the time the asset is acquired or placed in service. There is a corresponding increase to the carrying value of the asset, which is included in the proved properties line item in the accompanying balance sheets. The Company depletes the amount added to proved properties and recognizes expense in connection with accretion of the discounted liability over the remaining estimated economic lives of the properties.
The Company’s estimated asset retirement obligation liability is based on historical experience in abandoning wells, estimated economic lives, estimated costs to abandon the wells, and regulatory requirements. The liability is discounted using the credit-adjusted risk-free rate estimated at the time the liability is incurred, which ranges from 5% to 7%.

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A roll-forward of the Company's asset retirement obligation is as follows (in thousands):
 
 
Amount
Beginning balance as of December 31, 2018
$
29,405

Liabilities settled
 
(1,145
)
Additions
 
79

Accretion expense
 
823

Ending balance as of June 30, 2019
$
29,162



NOTE 10 - DERIVATIVES
The Company enters into commodity derivative contracts to mitigate a portion of its exposure to potentially adverse market changes in commodity prices and the associated impact on cash flows. All contracts are entered into for other-than-trading purposes. The Company’s derivatives include swaps, puts, and collars for oil and natural gas, and none of the derivative instruments qualifies as having hedging relationships.
In a typical commodity swap agreement, if the agreed upon published third-party index price is lower than the swap fixed price, the Company receives the difference between the index price and the agreed upon swap fixed price. If the index price is higher than the swap fixed price, the Company pays the difference.
A put gives the owner the right to sell the underlying commodity at a set price over the term of the contract. If the index settlement price is higher than the put fixed price, the put will expire worthless. If the settlement price is lower than the put fixed price, the Company will exercise the put and receive the difference between the settlement price and the put fixed price.
A cashless collar arrangement establishes a floor and ceiling price on future oil and gas production. When the settlement price is above the ceiling price, the Company pays the difference between the settlement price and the ceiling price. When the settlement price is below the floor price, the Company receives the difference between the settlement price and floor price. In the event that the settlement price is between the ceiling and the floor, no payment or receipt occurs.
A basis swap arrangement guarantees a price differential from a specified delivery point. The Company receives the difference between the price differential and the stated terms, if the price differential is greater than the stated terms. The Company pays the difference between the price differential and the stated terms, if the stated terms are greater than the price differential.

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As of June 30, 2019, the Company had entered into the following commodity derivative contracts:
 
 
Crude Oil
(NYMEX WTI)
 
Natural Gas
(CIG)
 
 
Bbls/day
 
Weighted Avg. Price per Bbl
 
MMBtu/day
 
Weighted Avg. Price per MMBtu
3Q19
 
 
 
 
 
 
 
 
Cashless Collar
 
4,000

 
$58.13/$75.54
 

 
Swap
 
5,000

 
$59.92
 
22,500

 
$2.13
4Q19
 
 
 
 
 
 
 
 
Cashless Collar
 
4,000

 
$58.13/$75.54
 

 
Swap
 
5,000

 
$59.92
 
22,500

 
$2.13
1Q20
 
 
 
 
 
 
 
 
Cashless Collar
 
5,000

 
$55.00/$62.88
 

 
Swap
 
3,000

 
$63.48
 
2,500

 
$2.40
2Q20
 
 
 
 
 
 
 
 
Cashless Collar
 
5,000

 
$55.00/$63.33
 

 
3Q20
 
 
 
 
 
 
 
 
Cashless Collar
 
2,000

 
$55.00/$63.14
 

 
4Q20
 
 
 
 
 
 
 
 
Cashless Collar
 
2,000

 
$55.00/$63.14
 

 

As of the filing date of this report, the Company had entered into the following commodity derivative contracts:
 
 
Crude Oil
(NYMEX WTI)
 
Natural Gas
(CIG Basis)
 
Natural Gas
(CIG)
 
 
Bbls/day
 
Weighted Avg. Price per Bbl
 
MMBtu/day
 
Weighted Avg. Basis Differential to CIG Price per MMBtu
 
MMBtu/day
 
Weighted Avg. Price per MMBtu
3Q19