Document
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, 2018
 Commission File Number:  001-35371
 Bonanza Creek Energy, Inc.
(Exact name of registrant as specified in its charter) 
Delaware
 
61-1630631
(State or other jurisdiction of
 
(I.R.S. Employer
incorporation or organization)
 
Identification No.)

410 17th Street, Suite 1400
 
 
Denver, Colorado
 
80202
(Address of principal executive offices)
 
(Zip Code)
(720) 440-6100
(Registrant’s telephone number, including area code)
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. x  Yes ¨  No
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). x  Yes ¨  No
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer”, “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.
Large accelerated filer ¨
 
Accelerated filer x
 
 
 
                                 Non-accelerated filer ¨ (Do not check if a smaller reporting company)
 
 
 
Emerging growth company ¨
 
Smaller reporting company ¨
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ¨
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). ¨  Yes x  No
Indicate by check mark whether the registrant has filed all documents and reports required to be filed by Sections 12, 13 or 15(d) of the Securities Exchange Act of 1934 subsequent to the distribution of securities under a plan confirmed by a court. x  Yes ¨ No
As of August 1, 2018, the registrant had 20,541,070 shares of common stock outstanding.
 

1
Table of Contents

BONANZA CREEK ENERGY, INC.
INDEX
 
 
    
    
PAGE
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 


2
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)
 
Successor
 
June 30, 2018
 
December 31, 2017
ASSETS
 

 
 

Current assets:
 

 
 

Cash and cash equivalents
$
21,989

 
$
12,711

Accounts receivable:
 

 
 

Oil and gas sales
38,830

 
28,549

Joint interest and other
13,926

 
3,831

Prepaid expenses and other
5,620

 
6,555

Inventory of oilfield equipment
1,434

 
1,019

Derivative assets
39

 
488

Total current assets
81,838

 
53,153

Property and equipment (successful efforts method):
 

 
 

Proved properties
552,858

 
555,341

Less: accumulated depreciation, depletion and amortization
(29,703
)
 
(17,032
)
Total proved properties, net
523,155

 
538,309

Unproved properties
179,735

 
183,843

Wells in progress
52,747

 
47,224

Oil and gas properties held for sale, net of accumulated depreciation, depletion and amortization of $2,583 in 2018 (note 4)
82,328

 
—

Other property and equipment, net of accumulated depreciation of $2,722 in 2018 and $2,224 in 2017
4,488

 
4,706

Total property and equipment, net
842,453

 
774,082

Long-term derivative assets
—

 
6

Other noncurrent assets
3,151

 
3,130

Total assets
$
927,442

 
$
830,371

LIABILITIES AND STOCKHOLDERS’ EQUITY
 

 
 

Current liabilities:
 

 
 

Accounts payable and accrued expenses (note 5)
$
50,242

 
$
62,129

Oil and gas revenue distribution payable
20,355

 
15,667

Derivative liability
28,416

 
11,423

Total current liabilities
99,013

 
89,219

 
 
 
 
Long-term liabilities:
 

 
 

Credit facility
60,000

 
—

Ad valorem taxes
19,803

 
11,584

Long-term derivative liability
4,657

 
2,972

Asset retirement obligations for oil and gas properties
28,154

 
38,262

Asset retirement obligations for oil and gas properties held for sale (note 4)
5,386

 
—

Total liabilities
217,013

 
142,037

 
 
 
 
Commitments and contingencies (note 7)


 


 
 
 
 
Stockholders’ equity:
 

 
 

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

 
—

Common stock, $.01 par value, 225,000,000 shares authorized, 20,534,799 and 20,453,549 issued and outstanding in 2018 and 2017, respectively
4,286

 
4,286

Additional paid-in capital
692,434

 
689,068

Retained earnings (deficit)
13,709

 
(5,020
)
Total stockholders’ equity
710,429

 
688,334

Total liabilities and stockholders’ equity
$
927,442

 
$
830,371

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

3
Table of Contents


BONANZA CREEK ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME (LOSS) (UNAUDITED)
(in thousands, except per share amounts)
 
 
Successor
 
 
Predecessor
 
Three Months Ended June 30, 2018
 
April 29, 2017 through June 30, 2017
 
 
April 1, 2017 through April 28, 2017
Operating net revenues:
 

 
 
 
 
 
Oil and gas sales
$
71,872

 
$
28,114

 
 
$
16,030

Operating expenses:
 

 
 
 
 
 
Lease operating expense
11,316

 
6,153

 
 
3,203

Gas plant and midstream operating expense
3,247

 
1,762

 
 
836

Gathering, transportation and processing
1,660

 
—

 
 
—

Severance and ad valorem taxes
6,071

 
2,408

 
 
1,352

Exploration
221

 
359

 
 
292

Depreciation, depletion and amortization
9,564

 
4,836

 
 
6,853

Abandonment and impairment of unproved properties
2,477

 
—

 
 
—

General and administrative (including $2,184, $7,949 and $391, respectively, of stock-based compensation)
9,917

 
16,139

 
 
2,998

Total operating expenses
44,473

 
31,657

 
 
15,534

Income (loss) from operations
27,399

 
(3,543
)
 
 
496

Other income (expense):
 

 
 
 
 
 
Derivative loss
(22,012
)
 
—

 
 
—

Interest expense
(805
)
 
(195
)
 
 
(1,088
)
Reorganization items, net (note 2)
—

 
—

 
 
97,811

Other income (expense)
277

 
158

 
 
(283
)
Total other income (expense)
(22,540
)
 
(37
)
 
 
96,440

Income (loss) from operations before taxes
4,859

 
(3,580
)
 
 
96,936

Income tax benefit (expense)
—

 
—

 
 
—

Net income (loss)
$
4,859

 
$
(3,580
)
 
 
$
96,936

 
 
 
 
 
 
 
Comprehensive income (loss)
$
4,859

 
$
(3,580
)
 
 
$
96,936

 
 
 
 
 
 
 
Basic net income (loss) per common share
$
0.24

 
$
(0.18
)

 
$
1.88

 
 
 
 
 
 
 
Diluted net income (loss) per common share
$
0.24

 
$
(0.18
)
 
 
$
1.85




 
 

 
 
Basic weighted-average common shares outstanding
20,488

 
20,369


 
49,902




 
 

 
 
Diluted weighted-average common shares outstanding
20,603

 
20,369


 
50,486

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




4
Table of Contents

BONANZA CREEK ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME (LOSS) (UNAUDITED)
(in thousands, except per share amounts)
 
Successor
 
 
Predecessor
 
Six Months Ended June 30, 2018
 
April 29, 2017 through June 30, 2017
 
 
January 1, 2017 through April 28, 2017
Operating net revenues:
 

 
 
 
 
 

Oil and gas sales
$
136,064

 
$
28,114

 
 
$
68,589

Operating expenses:
 

 
 
 
 
 

Lease operating expense
21,775

 
6,153

 
 
13,128

Gas plant and midstream operating expense
6,860

 
1,762

 
 
3,541

Gathering, transportation and processing
3,998

 
—

 
 
—

Severance and ad valorem taxes
11,303

 
2,408

 
 
5,671

Exploration
250

 
359

 
 
3,699

Depreciation, depletion and amortization
17,072

 
4,836

 
 
28,065

Abandonment and impairment of unproved properties
4,979

 
—

 
 
—

Unused commitments
21

 
—

 
 
993

General and administrative (including $3,192, $7,949 and $2,116, respectively, of stock-based compensation)
19,451

 
16,139

 
 
15,092

Total operating expenses
85,709

 
31,657

 
 
70,189

Income (loss) from operations
50,355

 
(3,543
)
 
 
(1,600
)
Other income (expense):
 

 
 
 
 
 

Derivative loss
(30,754
)
 
—

 
 
—

Interest expense
(1,162
)
 
(195
)
 
 
(5,656
)
Reorganization items, net (note 2)
—

 
—

 
 
8,808

Other income
290

 
158

 
 
1,108

Total other income (expense)
(31,626
)
 
(37
)
 
 
4,260

Income (loss) from operations before taxes
18,729

 
(3,580
)
 
 
2,660

Income tax benefit (expense)
—

 
—

 
 
—

Net income (loss)
$
18,729

 
$
(3,580
)
 
 
$
2,660

 
 
 
 
 
 
 
Comprehensive income (loss)
$
18,729

 
$
(3,580
)
 
 
$
2,660

 
 
 
 
 
 
 
Basic net income (loss) per common share
$
0.91

 
$
(0.18
)
 
 
$
0.05

 
 
 
 
 
 
 
Diluted net income (loss) per common share
$
0.91

 
$
(0.18
)
 
 
$
0.05

 
 
 
 
 
 
 
Basic weighted-average common shares outstanding
20,471

 
20,369

 
 
49,559

 
 
 
 
 
 
 
Diluted weighted-average common shares outstanding
20,538

 
20,369

 
 
50,971

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


5
Table of Contents

BONANZA CREEK ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY (UNAUDITED)
(in thousands, except share amounts)
 
 
 
 
 
 
 
Additional
 
Retained
 
 
 
 
 
Common Stock
 
Paid-In
 
Earnings
 
 
 
 
    
Shares
    
Amount
    
Capital
    
(Deficit)
    
Total
Balances, December 31, 2017
 
20,453,549

 
$
4,286

 
$
689,068

 
$
(5,020
)
 
$
688,334

Restricted common stock issued
 
78,109

 
 
—

 
 
—

 
 
—

 
 
—

Restricted stock used for tax withholdings
 
(24,050
)
 
 
—

 
 
(794
)
 
 
—

 
 
(794
)
Exercise of stock options
 
27,191

 
 
—

 
 
968

 
 
—

 
 
968

Stock-based compensation
 
—

 
 
—

 
 
3,192

 
 
—

 
 
3,192

Net income
 
—

 
 
—

 
 
—

 
 
18,729

 
 
18,729

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.



6
Table of Contents

BONANZA CREEK ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(UNAUDITED)
(in thousands)
 
Successor
 
 
Predecessor
 
Six Months Ended June 30, 2018
 
April 29, 2017 through June 30, 2017
 
 
January 1, 2017 through April 28, 2017
Cash flows from operating activities:
 

 
 
 
 
 

Net income (loss)
$
18,729

 
$
(3,580
)
 
 
$
2,660

Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities:
 
 
 
 
 
 

Depreciation, depletion and amortization
17,072

 
4,836

 
 
28,065

Non-cash reorganization items
—

 
—

 
 
(44,160
)
Abandonment and impairment of unproved properties
4,979

 
—

 
 
—

Well abandonment costs and dry hole expense
—

 
64

 
 
2,931

Stock-based compensation
3,192

 
7,949

 
 
2,116

Amortization of deferred financing costs and debt premium
—

 
—

 
 
374

Derivative loss
30,754

 
—

 
 
—

Derivative cash settlements
(11,622
)
 
—

 
 
—

Other
172

 
5

 
 
18

Changes in current assets and liabilities:
 
 
 
 
 
 

Accounts receivable
(20,376
)
 
6,420

 
 
(6,640
)
Prepaid expenses and other assets
935

 
270

 
 
963

Accounts payable and accrued liabilities
(889
)
 
(19,338
)
 
 
(5,880
)
Settlement of asset retirement obligations
(797
)
 
(459
)
 
 
(331
)
Net cash provided by (used in) operating activities
42,149

 
(3,833
)
 
 
(19,884
)
Cash flows from investing activities:
 

 
 
 
 
 

Acquisition of oil and gas properties
(1,295
)
 
(4,982
)
 
 
(445
)
Exploration and development of oil and gas properties
(91,482
)
 
(4,913
)
 
 
(5,123
)
Proceeds from sale of oil and gas properties
20

 
—

 
 
—

Additions to property and equipment - non oil and gas
(280
)
 
(161
)
 
 
(454
)
Net cash used in investing activities
(93,037
)
 
(10,056
)
 
 
(6,022
)
Cash flows from financing activities:
 

 
 
 
 
 

Proceeds from credit facility
60,000

 
—

 
 
—

Payments to credit facility
—

 
—

 
 
(191,667
)
Proceeds from sale of common stock
—

 
—

 
 
207,500

Proceeds from exercise of stock options
968

 
—

 
 
—

Payment of employee tax withholdings in exchange for the return of common stock
(794
)
 
(2,080
)
 
 
(427
)
Net cash provided by (used in) financing activities
60,174

 
(2,080
)
 
 
15,406

Net change in cash, cash equivalents and restricted cash
9,286

 
(15,969
)
 
 
(10,500
)
Cash, cash equivalents and restricted cash:
 

 
 
 
 
 

Beginning of period
12,782

 
68,406

 
 
78,906

End of period
$
22,068

 
$
52,437

 
 
$
68,406

Supplemental cash flow disclosure:
 

 
 
 
 
 

Cash paid for interest
$
906

 
$
193

 
 
$
3,509

Cash paid for reorganization items
$
—

 
$
918

 
 
$
52,968

Changes in working capital related to drilling expenditures
$
1,909

 
$
8,742

 
 
$
3,360

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

7
Table of Contents

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

NOTE 1 - ORGANIZATION AND BUSINESS
Bonanza Creek Energy, Inc. (“BCEI” or, together with our consolidated subsidiaries, the “Company”) is engaged primarily in acquiring, developing, exploiting and producing oil and gas properties. The Company's assets and operations are concentrated primarily in the Wattenberg Field in Colorado and in the Dorcheat Macedonia Field in southern Arkansas.
NOTE 2 - BASIS OF PRESENTATION
These unaudited condensed consolidated financial statements have been prepared in accordance with U.S. generally accepted accounting principles (“GAAP”) for interim financial statements and pursuant to the rules and regulations of the Securities and Exchange Commission. In the opinion of management, the accompanying unaudited condensed consolidated financial statements reflect all adjustments consisting of normal recurring adjustments as necessary for a fair presentation of our financial position and results of operations. Interim results of operations are not necessarily indicative of the results to be expected for the full fiscal year. As described below, however, prior financial statements are not comparable to our interim financial statements due to the adoption of fresh-start accounting.
The financial information as of December 31, 2017, has been derived from the audited financial statements contained in our Annual Report on Form 10-K for the year ended December 31, 2017 (“2017 Form 10-K”), but does not include all disclosures, including notes required by GAAP. As such, this quarterly report should be read in conjunction with the consolidated financial statements and related notes included in our 2017 Form 10-K. The Company follows the same accounting principles for preparing quarterly and annual reports.
On January 4, 2017, the Company and certain of its subsidiaries (collectively with the Company, the “Debtors”) filed voluntary petitions (the “Bankruptcy Petitions,” and the cases commenced thereby, the “Chapter 11 Cases”) under Chapter 11 of the United States Bankruptcy Code (the “Bankruptcy Code”) in the United States Bankruptcy Court for the District of Delaware (the “Bankruptcy Court”) to pursue the Debtors’ Joint Prepackaged Plan of Reorganization Under Chapter 11 of the Bankruptcy Code (as proposed, the “Plan”). The Bankruptcy Court granted the Debtors' motion seeking to administer all of the Debtors' Chapter 11 Cases jointly under the caption In re Bonanza Creek Energy, Inc., et al (Case No. 17-10015). The Debtors received bankruptcy court confirmation of their Plan on April 7, 2017, and emerged from bankruptcy on April 28, 2017 (the “Effective Date”). Although the Company is no longer a debtor-in-possession, the Company was a debtor-in-possession during a portion of the quarter ended June 30, 2017.
Upon emergence from bankruptcy, the Company adopted fresh-start accounting and became a new entity for financial reporting purposes. As a result of the application of fresh-start accounting and the effects of the implementation of the Plan, the Company’s condensed consolidated financial statements after April 28, 2017 are not comparable with the financial statements on or prior to April 28, 2017. The Company's condensed consolidated financial statements and related footnotes are presented with a black line division which delineates the lack of comparability between amounts presented after April 28, 2017 and dates prior thereto.
References to “Successor” or “Successor Company” relate to the financial position and results of operations of the reorganized Company subsequent to April 28, 2017. References to “Predecessor” or “Predecessor Company” relate to the financial position and results of operations of the Company on or prior to April 28, 2017. References to “Current Successor Quarter” and “Current Successor Period” relate to the three and six months ended June 30, 2018, respectively. References to “Prior Successor Quarter” and “Prior Successor Period” relate to the period of April 29, 2017 through June 30, 2017. References to “Prior Predecessor Quarter” relates to the period of April 1, 2017 through April 28, 2017 and “Prior Predecessor Period” relates to the period of January 1, 2017 through April 28, 2017.
Fresh-Start Accounting
The Company adopted fresh-start accounting, pursuant to FASB Accounting Standards Codification (“ASC”) 852, Reorganizations, and applied the provisions thereof to its financial statements with no beginning retained earnings or deficit as of the fresh-start reporting date. The cancellation of all existing shares outstanding on the Effective Date and issuance of new shares of the Successor Company caused a related change of control of the Company under ASC 852.
Under fresh-start accounting, reorganization value represents the fair value of the Successor Company’s total assets and is intended to approximate the amount a willing buyer would pay for the assets immediately after restructuring. Under application of fresh-start accounting, the Company allocated the reorganization value to its individual assets based on their estimated fair values at the date it applied fresh start accounting.

8
Table of Contents

Reorganization Items, Net    
Subsequent to January 4, 2017, and through the date of emergence, all expenses, gains, and losses directly associated with the reorganization were reported as reorganization items, net in the accompanying condensed consolidated statements of operations and comprehensive income (loss) (“accompanying statements of operations”). The following table summarizes reorganization items (in thousands):
Fresh-start related:
 
Gain on settlement of liabilities subject to compromise
$
412,852

Payment on revolving credit facility fees and remaining unaccrued 2016 STIP
(1,007
)
Fresh-start valuation adjustments
(311,361
)
Total fresh-start reorganization items, net
$
100,484

Prior predecessor quarter professional fees and other
(2,673
)
Prior predecessor quarter reorganization items, net
97,811

Prior predecessor period reorganization:
 
Legal and professional fees and expenses
(31,662
)
Write-off of debt issuance and premium costs
(6,156
)
Make-whole payment on Senior Notes
(51,185
)
Total prior predecessor period reorganization items, net
$
(89,003
)
 
 
Total reorganization items, net
$
8,808

Principles of Consolidation
     The balance sheets include the accounts of the Company and its wholly owned subsidiaries, Bonanza Creek Energy Operating Company, LLC, Bonanza Creek Energy Resources, LLC, Bonanza Creek Energy Upstream LLC, Bonanza Creek Energy Midstream, LLC, Holmes Eastern Company, LLC and Rocky Mountain Infrastructure, LLC. All significant intercompany accounts and transactions have been eliminated.
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.
Accounting Pronouncements Recently Adopted
In May 2014, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Codification (“ASC”) Update No. 2014-09, Revenue from Contracts with Customers (Topic 606) (“ASC 606”) for the recognition of revenue from contracts with customers. Several additional related updates have been issued since that point. In summary, revenue recognition would occur upon the transfer of promised goods or services to customers in an amount that reflects the consideration to which the Company expects to be entitled in exchange for those goods or services. The guidance also requires enhanced financial statement disclosures over revenue recognition and provisions regarding future revenues and expenses under a gross-versus-net presentation.
The standard is required to be adopted using either the full retrospective approach, with all prior periods presented adjusted, or the modified retrospective approach, with a cumulative adjustment to retained earnings on the opening balance sheet. The standard is effective for annual reporting periods beginning after December 15, 2017, and interim periods within those annual periods. We adopted the new standard on January 1, 2018 and its adoption did not have a significant impact on our financial statements. Please refer to Note 3 - Revenue Recognition for additional discussion.
In January 2016, the FASB issued Update No. 2016-01 - Financial Instruments - Overall to require separate presentation of financial assets and financial liabilities by measurement category and form of financial asset on the balance sheet or the accompanying notes to the financial statements. This authoritative guidance is effective for fiscal years beginning after December 15, 2017 and interim periods within those fiscal years. We adopted the new standard on January 1, 2018 and its adoption did not have a material impact on our financial statements and disclosures.

9
Table of Contents

In August 2016, the FASB issued Update No. 2016-15 - Classification of Certain Cash Receipts and Cash Payments, which clarifies the presentation of specific cash receipts and cash payments within the statement of cash flows. This authoritative accounting guidance is effective for annual periods, and interim periods within those annual periods, beginning after December 15, 2017. Early adoption is permitted. We adopted the new standard on January 1, 2018 and its adoption did not have a material impact on our statements of cash flows and related disclosures.
In November 2016, the FASB issued Update No. 2016-18, Statement of Cash Flows (Topic 230): Restricted Cash. This update clarifies how entities should present restricted cash and restricted cash equivalents in the statement of cash flows by including them with cash and cash equivalents when reconciling the total beginning and ending amounts for the periods shown on the statement of cash flows. This guidance is to be applied using a retrospective method and is effective for annual periods, and interim periods within those annual periods, beginning after December 15, 2017. Early adoption is permitted. We adopted the new standard on January 1, 2018 and the prior period has been adjusted to conform to the current period presentation, which resulted in an increase in cash used in investing activities of $0.1 million for the Prior Predecessor Period.
The following table provides a reconciliation of cash, cash equivalents and restricted cash reported within the balance sheets that sums to the total of such amounts shown in the accompanying condensed consolidated statements of cash flows (in thousands):
 
Successor
 
As of June 30, 2018
 
As of December 31, 2017
Cash and cash equivalents
$
21,989

 
$
12,711

Restricted cash included in other noncurrent assets
79

 
71

Total cash, cash equivalents and restricted cash as shown in the statements of cash flows
$
22,068

 
$
12,782

Restricted cash consists of funds for road maintenance and repairs.
In January 2017, the FASB issued Update No. 2017-01, Business Combinations (Topic 805): Clarifying the Definition of a Business. This update clarifies the definition of a business with the objective of adding guidance to assist entities with evaluating whether transactions should be accounted for as acquisitions (or disposals) of assets or businesses. This guidance is to be applied using a prospective method and is effective for annual periods, and interim periods within those annual periods, beginning after December 15, 2017. Early adoption is permitted. We adopted this new standard on January 1, 2018 and will apply it to any future acquisitions or disposals of assets or business.
In February 2017, the FASB issued Update No. 2017-05, Other Income-Gains and Losses from the Derecognition of Nonfinancial Assets (Subtopic 610-20): Clarifying the Scope of Asset Derecognition Guidance and Accounting for Partial Sales of Nonfinancial Assets. This update is meant to clarify existing guidance and to add guidance for partial sales of nonfinancial assets. This guidance is to be applied using a full retrospective method or a modified retrospective method as outlined in the guidance and is effective at the same time as Update 2014-09, Revenue from Contracts with Customers (Topic 606). We adopted this new standard on January 1, 2018 and its adoption did not have a material impact on our financial statements and disclosures.
In May 2017, the FASB issued Update No. 2017-09 (ASU 2017-09) Compensation - Stock Compensation (Topic 718). The purpose of this update is to provide clarity as to which modifications of awards require modification accounting under Topic 718, whereas previously issued guidance frequently resulted in varying interpretations and a diversity of practice. An entity should employ modification accounting unless the following are met: (1) the fair value of the award is the same immediately before and after the award is modified; (2) the vesting conditions are the same under both the modified award and the original award; and (3) the classification of the modified award is the same as the original award, either equity or liability. Regardless of whether modification accounting is utilized, award disclosure requirements under Topic 718 remain unchanged. This guidance will be effective for annual and interim periods beginning after December 15, 2017. We adopted the new standard on the effective date of January 1, 2018 and its adoption did not have a material impact on our financial statements and disclosures.

10
Table of Contents

Recently Issued Accounting Standards
In February 2016, the FASB issued Update No. 2016-02 – Leases (ASU 2016-02) to increase transparency and comparability among organizations by recognizing lease assets and lease liabilities on the balance sheet and disclosing key information about leasing arrangements. In January 2018, the FASB issued Update No. 2018-01 Leases (Topic 842) - Land Easement Practical Expedient for Transition to Topic 842, which permits an entity to elect an optional transition practical expedient to not evaluate land easements existing or expiring before the entity’s adoption of ASU 2016-02 and not previously accounted for as leases. Furthermore, in July 2018, the FASB issued Update No. 2018-11 (ASU 2018-11): Leases (Topic 842): Targeted Improvements, which provides for another transition method, in addition to the existing transition method, by allowing entities to initially apply the new leases standard at the adoption date (such as January 1, 2019) and recognize a cumulative-effect adjustment to the opening balance of retained earnings in the period of adoption (i.e. comparative periods presented in the financial statements will continue to be in accordance with current GAAP (Topic 840, Leases)). The standard will be effective for annual and interim periods beginning after December 15, 2018, with earlier application permitted. The Company plans on adopting this guidance on January 1, 2019, using the modified retrospective approach.
In the normal course of business, we enter into operating lease agreements to support our exploration and development operations and lease assets such as drilling rigs, field services, well equipment, pipeline capacity, office space and other assets. Although we continue to assess the impact of the standard on our consolidated financial statements, we believe adoption and implementation will result in an increase in assets and liabilities as well as additional disclosures. We do not expect a material impact on our consolidated statement of operations. We have developed and are executing a project plan, which includes contract review and assessment, as well as evaluation of our systems, processes and internal controls. In addition, we plan to implement new lease accounting software.
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, 2018, and through the filing date of this report.
NOTE 3 - REVENUE RECOGNITION
On January 1, 2018, the Company adopted ASC 606, using the modified retrospective approach. Results for reporting periods beginning January 1, 2018, are presented in accordance with ASC 606, while prior period amounts are reported in accordance with ASC 605 - Revenue Recognition.
The impact of adoption on our Current Successor Periods results is as follows (in thousands):
 
Three Months Ended June 30, 2018
 
As Unadjusted(1)
 
ASC 606 Adjustments
 
As Reported
Operating Revenues:
 
 
 
 
 
    Oil sales
$
60,751

 
$
—

 
$
60,751

    Natural gas sales
 
4,244

 
 
694

 
 
4,938

    NGLs sales
 
5,217

 
 
966

 
 
6,183

Oil and gas sales
$
70,212

 
$
1,660

 
$
71,872

 
 
 
 
 
 
 
 
 
Operating expenses:
 
 
 
 
 
 
 
 
    Gathering, transportation and processing
$
—

 
$
1,660

 
$
1,660

 
 
 
 
 
 
 
 
 
Net income
$
4,859

 
$
—

 
$
4,859


11
Table of Contents

 
Six Months Ended June 30, 2018
 
As Unadjusted(1)
 
ASC 606 Adjustments
 
As Reported
Operating Revenues:
 
 
 
 
 
    Oil sales
$
112,714

 
$
—

 
$
112,714

    Natural gas sales
 
9,362

 
 
1,797

 
 
11,159

    NGLs sales
 
9,990

 
 
2,201

 
 
12,191

Oil and gas sales
$
132,066

 
$
3,998

 
$
136,064

 
 
 
 
 
 
 
 
 
Operating expenses:
 
 
 
 
 
 
 
 
    Gathering, transportation and processing
$
—

 
$
3,998

 
$
3,998

 
 
 
 
 
 
 
 
 
Net income
$
18,729

 
$
—

 
$
18,729

____________________
(1) This column excludes the impact of ASC 606 and is consistent with the presentation prior to January 1, 2018.
Revenue from Contracts with Customers
Sales of oil, natural gas and natural gas liquids (“NGLs”) are recognized when performance obligations are satisfied at the point control of the product is transferred to the customer. Virtually all of our contracts’ pricing provisions are tied to a market index, with certain adjustments based on, among other factors, whether a well delivers to a gathering or transmission line, quality of the oil or natural gas, and prevailing supply and demand conditions. As a result, the price of the oil, natural gas, and NGLs fluctuates to remain competitive with other available oil, natural gas, and NGLs supplies.
Performance Obligations
Oil Sales
Under our oil sales contracts we sell oil production at the wellhead, or other contractually agreed-upon delivery 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.
Natural Gas and NGLs Sales
Under our natural gas processing contracts, we deliver natural gas to an agreed-upon delivery point. The delivery points are specified within each contract, and the transfer of control varies between the inlet and outlet of the midstream processing facility. The midstream processing entity gathers and processes the natural gas and remits proceeds to the Company for the resulting sales of NGLs and residue gas. For the contracts where we maintain control through the outlet of the midstream processing facility, we recognize revenue on a gross basis, with gathering, transportation and processing fees presented as an expense in our consolidated statements of operations. Alternatively, for those contracts where the Company relinquishes control at the inlet of the midstream processing facility, the Company recognizes natural gas and NGLs revenues based on the contracted amount of the proceeds received from the midstream processing entity and, as a result, we recognize revenue on a net basis.
Working Interest Partners
The Company and its working interest partners have entered into joint operating agreements, which govern the marketing and selling of the working interest partner's share of oil, natural gas and NGLs. When selling oil, natural gas and NGLs on behalf of working interest owners, the Company is acting as an agent and thus reports the revenue on a net basis.
Transaction Price
As noted above, the transaction price is generally tied to a market index, net of adjustments or price differentials, with the variable consideration being the estimation process and related accruals; however, any identified differences between our revenue estimates and actual revenue received historically have not been significant.


12
Table of Contents

As further described in Note 7 - Commitments and Contingencies, one contract with NGL Crude Logistics, LLP (“NGL”, known as the “NGL agreement”) has an additional aspect of variable consideration related to the minimum volume commitments (“MVCs”) as specified in the agreement. On an on-going basis, the Company performs an analysis of expected risk adjusted production applicable to the NGL agreement based on approved production plans to determine if liquidated damages to NGL are probable. As of June 30, 2018, the Company believes that the volumes delivered to NGL will be in excess of the MVCs required then and for the upcoming approved production plan. As a result of this analysis, to date, no variable consideration related to potential liquidated damages has been considered in the transaction price for the NGL agreement.
Transaction Price Allocated to Remaining Performance Obligations
Under our sales contracts, each unit of product represents a separate performance obligation; therefore, future volumes are wholly unsatisfied and the transaction price for remaining performance obligations is determined in accordance with the preceding section during the period in which the performance obligation is satisfied. For our product sales that have a contract term of one year or less, we applied the practical expedient under the guidance, which states that a Company is not required to disclose the transaction price allocated to remaining performance obligations if the performance obligation is part of a contract that has an original expected duration of one year or less.
Contract Balances
Under our product sales contracts, we invoice customers once our performance obligations have been satisfied, at which point payment is unconditional. Accordingly, our product sales contracts do not give rise to contract assets or liabilities under this guidance. At June 30, 2018 and December 31, 2017, our receivables from contracts with customers were $38.8 million and $28.5 million, respectively.
Prior-Period Performance Obligations
We record revenue in the month production is delivered to the purchaser. However, settlement statements for certain natural gas and NGLs sales may not be received for 30 to 60 days after the date production is delivered, and as a result, we are required to estimate the amount of production delivered to the purchaser and the price that will be received for the sale of the product. We record the differences between our estimates and the actual amounts received for product sales in the month in which payment is received from the purchaser. We have existing internal controls for our revenue estimation process and related accruals, and any identified differences between our revenue estimates and actual revenue received historically have not been significant. For the period from January 1, 2018 through June 30, 2018, revenue recognized in the reporting period related to performance obligations satisfied in prior reporting periods was not material.
NOTE 4 - ASSETS HELD FOR SALE
During the first quarter of 2018, the Company established a plan to sell all of the Company's assets within its Mid-Continent region and North Park Basin, at which point they were deemed held for sale.
The Company sold its North Park Basin on March 9, 2018 for minimal net proceeds and full release of all current and future obligations resulting in a minimal net loss. As of December 31, 2017, the assets within the Company's North Park Basin represented $5.4 million, net of accumulated depreciation, depletion and amortization; and a corresponding asset retirement obligation liability of approximately $5.4 million.
As of June 30, 2018, the Company had $82.3 million of oil and gas properties held for sale, net of $2.6 million accumulated depreciation, depletion and amortization as presented in the accompanying condensed consolidated balance sheets (“accompanying balance sheets”). These properties consist of all assets within the Company's Mid-Continent region. There is a corresponding asset retirement obligation liability of approximately $5.4 million in the asset retirement obligations for oil and gas properties held for sale in the accompanying balance sheets. There were no other material assets or liabilities associated with the assets held for sale.
On August 6, 2018, the Company entered into an agreement to simultaneously close and divest of its assets within its Mid-Continent region for $117.0 million, subject to customary purchase price adjustments.

13
Table of Contents

NOTE 5 - ACCOUNTS PAYABLE AND ACCRUED EXPENSES
Accounts payable and accrued expenses contain the following (in thousands):
 
Successor
 
As of June 30, 2018
 
As of December 31, 2017
Drilling and completion costs
$
23,742

 
$
21,833

Accounts payable trade
10,326

 
6,256

Accrued general and administrative cost
3,111

 
10,025

Lease operating expense
4,039

 
5,005

Accrued interest
506

 
250

Accrued oil and gas hedging
2,325

 
808

Production and ad valorem taxes and other
6,193

 
17,952

Total accounts payable and accrued expenses
$
50,242

 
$
62,129

NOTE 6 - LONG-TERM DEBT 
Long-term debt consisted of the following (in thousands):
 
Successor
 
As of June 30, 2018
 
As of December 31, 2017
Credit facility
$
60,000

 
$
—

Total long-term debt
$
60,000

 
$
—

Credit Facility
Upon emergence from bankruptcy, the Company entered into a new revolving credit facility, as the borrower, with KeyBank National Association, as the administrative agent, and certain lenders party thereto (the “credit facility”). The borrowing base of $191.7 million is redetermined semiannually, as early as April and October of each year. Effective May 31, 2018, the credit facility's $191.7 million borrowing base was reaffirmed, at the request of the Company, and certain provisions related to the disposition of assets of the Company to provide the Company with greater flexibility to participate in asset swaps was adjusted.
The credit facility restricts, among other items, certain dividend payments, additional indebtedness, purchase of margin stock, asset sales, loans, investments and mergers. The credit facility also contains certain financial covenants, which require the maintenance of certain financial and leverage ratios, as defined by the credit facility. The credit facility states that the Company's leverage ratio of indebtedness to earnings before interest, income taxes, depreciation, depletion, and amortization, exploration expense and other non-cash charges (“EBITDAX”) is not to exceed 3.50 to 1.00. The Company must maintain a minimum current ratio of 1.00 to 1.00 and a minimum interest coverage ratio of trailing twelve-month EBITDAX to trailing twelve-month interest expense of 2.50 to 1.00 as of the end of the respective fiscal quarter. As of June 30, 2018, and through the filing date of this report, the Company was in compliance with all financial and non-financial covenants of the credit facility.
 The credit facility provides for interest rates plus an applicable margin to be determined based on London Interbank Offered Rate (“LIBOR”) or a base rate, at the Company’s election. LIBOR borrowings bear interest at LIBOR, plus a margin of 3.00% to 4.00% depending on the utilization level, and the base rate borrowings bear interest at the “Reference Rate,” as defined in the credit facility, plus a margin of 2.00% to 3.00% depending on the utilization level.

14
Table of Contents

NOTE 7 - COMMITMENTS AND CONTINGENCIES
Legal Proceedings 
From time to time, the Company is involved in various commercial and regulatory claims, litigation and other legal proceedings that arise in the ordinary course of its business. The Company assesses these claims in an effort to determine the degree of probability and range of possible loss for potential accrual in its condensed consolidated financial statements. In accordance with accounting authoritative guidance, an accrual is recorded for a loss contingency when its occurrence is probable and damages can be reasonably estimated based on the most likely anticipated outcome or the minimum amount within a range of possible outcomes. Because legal proceedings are inherently unpredictable and unfavorable resolutions could occur, assessing contingencies is highly subjective and requires judgments about uncertain future events. When evaluating contingencies, the Company may be unable to provide a meaningful estimate due to a number of factors, including the procedural status of the matter in question, the presence of complex or novel legal theories, and/or the ongoing discovery and development of information important to the matters. The Company regularly reviews contingencies to determine the adequacy of its accruals and related disclosures. No claims have been made, nor is the Company aware of any material uninsured liability which the Company may have, as it relates to any environmental cleanup, restoration or the violation of any rules or regulations. As of the filing date of this report, there were no material pending or overtly threatened legal actions against the Company of which it is aware.
As previously described in our 2017 Form 10-K, the Company and the Colorado Department of Public Health and Environment (“CDPHE”) agreed to a Compliance Order on Consent (the “COC”) resolving the matters addressed by a compliance advisory issued to the Company for certain storage tank facilities located in the Wattenberg Field with respect to applicable air quality regulations. Pursuant to the terms of the COC, the Company paid an administrative penalty of $0.2 million in 2017. The Company must also adopt procedures and processes to address the monitoring, reporting, and control of air emissions. The COC further sets forth compliance requirements and criteria for continued operations and contains provisions regarding record-keeping, modifications to the COC, circumstances under which the COC may terminate with respect to certain wells and facilities, and the sale or transfer of operational or ownership interests covered by the COC. In order to be in compliance, the Company incurred $0.7 million in 2017, and currently anticipates spending $3.5 million in 2018, and $3.1 million for 2019 through 2022. The COC can be terminated after four years with a showing of substantial compliance and CDPHE approval.
Commitments
The purchase agreement to deliver fixed determinable quantities of crude oil to NGL became effective on April 28, 2017. The terms of the NGL agreement includes defined volume commitments over an initial seven-year term. Under the terms of the NGL agreement, the Company will be required to make periodic deficiency payments for any shortfalls in delivering minimum volume commitments, which are set in six-month periods beginning in January 2018. There were no minimum volume commitments for the year ending December 31, 2017. During 2018, the average minimum volume commitment will be approximately 10,100 barrels per day, and the minimum volume commitment increases by approximately 41% from 2018 to 2019 and approximately 3% each year thereafter for the remainder of the contract, to a maximum of approximately 16,000 barrels per day. The aggregate financial commitment fee over the remaining term, based on the minimum volume commitment schedule (as defined in the agreement) and the applicable differential fee, is $145.5 million as of June 30, 2018. Upon notifying NGL at least twelve months prior to the expiration date of the NGL agreement, the Company may elect to extend the term of the NGL agreement for up to three additional years.
On April 29, 2017, the Company entered into a new office lease agreement to rent office facilities. The lease is non-cancelable and expires in February 2022.

15
Table of Contents

The annual minimum commitment payments under the NGL agreement and the office lease for the next five years as of June 30, 2018 are presented below (in thousands):
 
    
NGL Commitments(1)
 
Office Lease Commitments
 
Total
2018
 
$
6,664

$
—

$
6,664

2019
 
 
22,176

 
1,224

 
23,400

2020
 
 
27,949

 
1,335

 
29,284

2021
 
 
28,791

 
1,423

 
30,214

2022
 
 
29,485

 
240

 
29,725

2023 and thereafter
 
 
30,448

 
—

 
30,448

Total
 
$
145,513

$
4,222

$
149,735

_______________________________
(1) The above calculation is based on the minimum volume commitment schedule (as defined in the NGL agreement) and applicable differential fees.
There have been no other material changes from the commitments disclosed in the notes to the Company’s consolidated financial statements included in our 2017 Form 10-K.
NOTE 8 - STOCK-BASED COMPENSATION
2017 Long Term Incentive Plan
Upon emergence from bankruptcy, the Company adopted a new Long Term Incentive Plan (the “2017 LTIP”), as established by the pre-emergence Board, which allows for the issuance of restricted stock units (“RSUs”), performance stock units (“PSUs”) and options. See below for further discussion of awards granted under the 2017 LTIP.
Restricted Stock Units
The 2017 LTIP, established by the pre-emergence Board, allows for the issuance of RSUs to members of the Board of Directors and employees of the Company at the discretion of the Board of Directors. Each RSU represents one share of the Company's common stock to be released from restriction upon completion of the vesting period. The awards typically vest in one-third increments over three years. The RSUs are valued at the grant date share price and are recognized as general and administrative expense over the vesting period of the award.
The Company granted 343,574 RSUs with a fair value of $9.5 million during the Current Successor Period. Total expense recorded for RSUs, inclusive of grants to the members of the Board of Directors, for the Current Successor Period was $2.4 million. As of June 30, 2018, unrecognized compensation cost was $13.0 million and will be amortized through 2023.
A summary of the status and activity of non-vested restricted stock units for the Current Successor Period is presented below:
 
Restricted Stock Units
 
Weighted-
Average
Grant-Date
Fair Value    
Non-vested at beginning of year
261,165

 
$
34.93

Granted
343,574

 
$
27.56

Vested
(78,109
)
 
$
34.36

Forfeited
(38,073
)
 
$
30.88

Non-vested at end of quarter
488,557

 
$
30.15

Performance Stock Units
The 2017 LTIP, established by the pre-emergence Board, allows for the issuance of PSUs to employees at the sole discretion of the Board of Directors. 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

16
Table of Contents

compared with the TSRs of a group of peer companies for the same 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. 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. 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 Current Successor Quarter, the Company granted 59,641 PSUs to certain officers with a fair value of $1.8 million. The Company recognized compensation expense of $0.1 million for the Current Successor Quarter. As of June 30, 2018, unrecognized compensation cost was $1.7 million and will be amortized through 2020.
The following table presents the assumptions used to determine the fair value of the portion of the PSUs tied to TSR that were granted during the Current Successor Quarter:
 
 
For the Three Months Ended June 30, 2018
Expected term of award (in years)
 
3

Risk-free interest rate
 
2.76
%
Expected daily volatility
 
2.6
%
A summary of the status and activity of performance stock units for the Current Successor Period is presented below:
 
Performance Stock Units
 
Weighted-
Average
Grant-Date
Fair Value    
Non-vested at beginning of year
—

 
$
—

Granted (1)
59,641

 
$
29.92

Vested
—

 
$
—

Non-vested at end of quarter (1)
59,641

 
$
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, established by the pre-emergence Board, 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 are recognized as general and administrative expense over the vesting period of the award.
There were no stock options granted during the Current Successor Quarter. Total expense recorded for stock options for the Current Successor Quarter was $0.7 million. As of June 30, 2018, unrecognized compensation cost was $1.6 million and will be amortized through 2020.

17
Table of Contents

A summary of the status and activity of non-vested stock options for the Current Successor Period is presented below:
 
Stock Options
 
Weighted-
Average
Exercise Price
 
Weighted-Average Remaining Contractual Term (in years)
 
Aggregate Intrinsic Value (in thousands)
Outstanding at beginning of year
197,271

 
$
34.36

 
9.3

 
$
—

Granted
—

 
—

 
—

 
$
—

Exercised
(27,191
)
 
34.36

 
—

 
$
—

Forfeited
(19,083
)
 
34.36

 
—

 
$
—

Outstanding at end of quarter
150,997

 
$
34.36

 
8.5

 
$
—

A summary of additional information related to options outstanding and exercisable as of June 30, 2018 is presented below:
Exercise Price
Number of Options Outstanding and Exercisable
Weighted-Average Remaining Contractual Life (in years)
$34.36
50,811
8.3
NOTE 9 - FAIR VALUE MEASUREMENTS
The Company follows fair value measurement authoritative guidance, which defines fair value, establishes a framework for using fair value to measure assets and liabilities, and expands disclosures about fair value measurements. The authoritative accounting guidance defines fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. The statement establishes a hierarchy for inputs used in measuring fair value that maximizes the use of observable inputs and minimizes the use of unobservable inputs by requiring that the most observable inputs be used when available. Observable inputs are inputs that market participants would use in pricing the asset or liability developed based on market data obtained from sources independent of the Company. Unobservable inputs are inputs that reflect the Company’s assumptions of what market participants would use in pricing the asset or liability developed based on the best information available in the circumstances. The hierarchy is broken down into three levels based on the reliability of the inputs as follows:
Level 1: Quoted prices are available in active markets for identical assets or liabilities 
Level 2: Quoted prices in active markets for similar assets and liabilities, quoted prices for identical or similar instruments in markets that are not active, and model-derived valuations whose inputs are observable or whose significant value drivers are observable
Level 3: Significant inputs to the valuation model are unobservable
Financial and non-financial assets and liabilities are to be classified based on the lowest level of input that is significant to the fair value measurement. The Company’s assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of the fair value of assets and liabilities and their placement within the fair value hierarchy levels.
The following tables present the Company's financial and non-financial assets and liabilities that were accounted for at fair value as of June 30, 2018 and December 31, 2017 and their classification within the fair value hierarchy (in thousands):
 
As of June 30, 2018
 
Level 1
 
Level 2
 
Level 3
Derivative assets(1)
$
—

 
$
39

 
$
—

Derivative liabilities(1)
$
—

 
$
33,073

 
$
—

Unproved properties(2)
$
—

 
$
—

 
$
179,735


18
Table of Contents

 
As of December 31, 2017
 
Level 1
 
Level 2
 
Level 3
Derivative assets(1)
$
—

 
$
494

 
$
—

Derivative liabilities(1)
$
—

 
$
14,395

 
$
—

Asset retirement obligations(3)
$
—

 
$
—

 
$
8,481

____________________________
(1)
This represents a financial asset or liability that is measured at fair value on a recurring basis
(2)
Represents non-financial assets that are measured at fair value on a nonrecurring basis. Please refer to the Unproved Oil and Gas Properties sections below for additional discussion.
(3)
Represents the revision to estimates of the asset retirement obligation, which is a non-financial liability that is measured at fair value on a nonrecurring basis. Please refer to the Asset Retirement Obligation section below for additional discussion.
Unproved Oil and Gas Properties
 Unproved oil and gas property costs are evaluated for impairment and reduced to fair value when there is an indication that the carrying costs may not be fully recoverable. To measure the fair value of unproved properties, the Company uses Level 3 inputs and the income valuation technique, which takes into account the following significant assumptions: future development plans, risk weighted potential resource recovery, remaining lease life, standard amortization and estimated reserve values. The Company impaired non-core acreage in the Wattenberg Field due to leases expiring, which had a carrying value of $184.7 million, to their fair value of $179.7 million, and recognized an impairment of unproved properties for the Current Successor Period of $5.0 million.
Asset Retirement Obligation
The Company utilizes the income valuation technique to determine the fair value of the asset retirement obligation liability at the point of inception by applying a credit-adjusted risk-free rate, which takes into account the Company’s credit risk, the time value of money, and the current economic state, to the undiscounted expected abandonment cash flows. Upon completion of wells and natural gas plants, the Company records an asset retirement obligation at fair value using Level 3 assumptions. Given the unobservable nature of the inputs, the initial measurement of the asset retirement obligation liability is deemed to use Level 3 inputs. There were no asset retirement obligations measured at fair value as of June 30, 2018. The Company had $8.5 million of asset retirement obligations recorded at fair value as of December 31, 2017.
Long-term Debt
The Company's credit facility approximates fair value as the applicable interest rates are floating. The outstanding balance under the credit facility as of June 30, 2018 was $60.0 million.  
NOTE 10 - ASSET RETIREMENT OBLIGATIONS
The Company recognizes an estimated liability for future costs to abandon its oil and gas properties. The fair value of the asset retirement obligation is recorded as a liability when incurred, which is typically at the time the asset is acquired or placed in service. There is a corresponding increase to the carrying value of the asset which is included in the proved properties line item in the accompanying balance sheets. The Company depletes the amount added to proved properties and recognizes expense in connection with accretion of the discounted liability over the remaining estimated economic lives of the properties.
The Company’s estimated asset retirement obligation liability is based on historical experience in abandoning wells, estimated economic lives, estimated costs to abandon the wells, and regulatory requirements. The liability is discounted using the credit-adjusted risk-free rate estimated at the time the liability is incurred, which ranges from 5% to 7%.     

19
Table of Contents

A roll-forward of the Company's asset retirement obligation is as follows (in thousands):
Beginning balance as of December 31, 2017
$
38,262

Liabilities settled
 
(383
)
Additions
 
226

Accretion expense
 
912

Sold properties
 
(5,477
)
Ending balance as of June 30, 2018(1)
$
33,540

____________________________
(1)
Includes $5.4 million of asset retirement obligations associated with assets held for sale.
NOTE 11 - DERIVATIVES
The Company enters into commodity derivative contracts to mitigate a portion of its exposure to potentially adverse market changes in commodity prices and the associated impact on cash flows. All contracts are entered into for other-than-trading purposes. The Company’s derivatives include swaps, collar arrangements, and basis swaps 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.
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.

20
Table of Contents

As of June 30, 2018, the Company had entered into the following commodity derivative contracts:
 
 
Crude Oil
(NYMEX WTI)
 
Natural Gas
(NYMEX Henry Hub)
 
 
Bbls/day
 
Weighted Avg. Price per Bbl
 
MMBtu/day
 
Weighted Avg. Price per MMBtu
Q318
 
 
 
 
 
 
 
 
Cashless Collar
 
2,000

 
$43.00/$53.50
 
13,600

 
$2.75/$3.32
Swap
 
5,000

 
$57.87
 
—

 
—
Q418
 
 
 
 
 
 
 
 
Cashless Collar
 
2,000

 
$43.00/$53.50
 
12,600

 
$2.75/$3.35
Swap
 
5,000

 
$58.07
 
—

 
—
Q119
 
 
 
 
 
 
 
 
Cashless Collar
 
2,000

 
$43.00/$54.53
 
7,600

 
$2.75/$3.22
Swap
 
5,000

 
$59.33
 
—

 
—
Q219
 
 
 
 
 
 
 
 
Cashless Collar
 
3,330

 
$51.81/$64.23
 
2,505

 
$2.75/$3.22
Swap
 
4,500

 
$58.32
 
—

 
—
Q319
 
 
 
 
 
 
 
 
Swap
 
3,000

 
$55.00
 
—

 
—
Q419
 
 
 
 
 
 
 
 
Swap
 
3,000

 
$55.00
 
—

 
—
Subsequent to quarter-end, the Company entered into a natural gas basis swap between NYMEX Henry Hub price and the Colorado Interstate Gas (CIG) Rockies Natural Gas price, the index on which the majority of our natural gas is sold.
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
(NYMEX Henry Hub)
 
 
Bbls/day
 
Weighted Avg. Price per Bbl
 
MMBtu/day
 
Weighted Avg. Price per MMBtu
 
MMBtu/day
 
Weighted Avg. Basis Differential to NYMEX Henry Hub Price per MMBtu
Q318
 
 
 
 
 
 
 
 
 
 
 
 
Cashless Collar
 
2,000

 
$43.00/$53.50
 
13,600

 
$2.75/$3.32
 
—

 
—
Swap
 
5,000

 
$57.87
 
—

 
—
 
—

 
—
Basis Swap
 
—

 
—
 
—

 
—
 
8,354

 
$0.670
Q418
 
 
 
 
 
 
 
 
 
 
 
 
Cashless Collar
 
2,000

 
$43.00/$53.50
 
12,600

 
$2.75/$3.35
 
—

 
—
Swap
 
5,000

 
$58.07
 
—

 
—
 
—

 
—
Basis Swap
 
—

 
—
 
—

 
—
 
12,600

 
$0.670
Q119
 
 
 
 
 
 
 
 
 
 
 
 
Cashless Collar
 
2,000

 
$43.00/$54.53
 
7,600

 
$2.75/$3.22
 
—

 
—
Swap
 
5,000

 
$59.33
 
—

 
—
 
—

 
—
Basis Swap
 
—

 
—
 
—

 
—
 
7,600

 
$0.665
Q219
 
 
 
 
 
 
 
 
 
 
 
 
Cashless Collar
 
3,330

 
$51.81/64.23
 
2,505

 
$2.75/$3.22
 
—

 
—
Swap
 
4,500

 
$58.32
 
—

 
—
 
—

 
—
Q319
 
 
 
 
 
 
 
 
 
 
 
 
Swap
 
3,000

 
$55.00
 
—

 
—
 
—

 
—
Q419
 
 
 
 
 
 
 
 
 
 
 
 
Swap
 
3,000

 
$55.00
 
—

 
—
 
—

 
—

21
Table of Contents

Derivative Assets Fair Value
 The Company’s commodity derivatives are measured at fair value and are included in the accompanying balance sheets as derivative assets and liabilities.
 The following table contains a summary of all the Company’s derivative positions reported on the accompanying balance sheets as of June 30, 2018 and December 31, 2017 (in thousands):
 
 
 
Successor
 
 
 
As of June 30, 2018
 
As of December 31, 2017
 
Balance Sheet Location
 
Fair Value
 
Fair Value
Derivative Assets:
 
 
 
 
 

Commodity contracts
Current assets
 
$
39

 
$
488

Commodity contracts
Noncurrent assets
 
—

 
6

Derivative Liabilities:
 
 
 

 
 

Commodity contracts
Current liabilities
 
(28,416
)
 
(11,423
)
Commodity contracts
Long-term liabilities
 
(4,657
)
 
(2,972
)
Total derivative liabilities, net
 
 
$
(33,034
)
 
$
(13,901
)
The Company had not entered into any derivative contracts as of June 30, 2017. 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 June 30, 2018
 
Six Months Ended June 30, 2018
Derivative cash settlement gain (loss):
 
 
 

Oil contracts
$
(7,319
)
 
$
(11,825
)
Gas contracts
9

 
203

Total derivative cash settlement loss(1)
$
(7,310
)
 
$
(11,622
)
 
 
 
 
Change in fair value loss
$
(14,702
)
 
$
(19,132
)
 
 
 
 
Total derivative loss(1)
$
(22,012
)
 
$
(30,754
)
_______________________________
(1)
Total derivative loss and total derivative cash settlement loss for the Current Successor Quarter and Current Successor Period are reported in the derivative loss line item and derivative cash settlements line item in the accompanying condensed consolidated statements of cash flows, within cash flows from operating activities. 
NOTE 12 - EARNINGS PER SHARE
The Company 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 issued 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 8 - Stock-Based Compensation for additional discussion.

22
Table of Contents

The RSUs, PSUs, stock options, and warrants of the Company are all non-participating securities, and therefore, the Company used the treasury stock method to calculate earnings per share as shown in the following table (in thousands, except per share amounts):
 
Successor
 
Three Months Ended June 30, 2018
 
Six Months Ended June 30, 2018
 
April 29, 2017 through June 30, 2017
Net income (loss)
$
4,859

 
$
18,729

 
$
(3,580
)
 
 
 
 
 
 
Basic net income (loss) per common share
$
0.24

 
$
0.91

 
$
(0.18
)
 
 
 
 
 
 
Diluted net income (loss) per common share
$
0.24

 
$
0.91

 
$
(0.18
)
 
 
 
 
 
 
Weighted-average shares outstanding - basic
20,488

 
20,471

 
20,369

Add: dilutive effect of contingent stock awards
115

 
67

 
—

Weighted-average shares outstanding - diluted
20,603

 
20,538

 
20,369

There were 181,762 and 196,435 dilutive shares that were anti-dilutive for the Current Successor Quarter and Current Successor Period, respectively. The Company was in a net loss position for the Prior Successor Quarter, which made any potentially dilutive shares anti-dilutive. There were 717,201 anti-dilutive shares in the Prior Successor Quarter.
The Predecessor Company issued shares of restricted stock, which entitled the holders to receive non-forfeitable dividends, if and when the Predecessor Company was to declare a dividend, before vesting, thus making the awards participating securities. The awards are included in the calculation of earnings per share under the two-class method. The two-class method allocates earnings for the period between common shareholders and unvested participating shareholders, and allocates losses to common shareholders only.
The Predecessor Company issued performance stock units (“PSUs”), which represented the right to receive, upon settlement of the PSUs, a number of shares of the Predecessor Company’s common stock that range from zero to two times the number of PSUs granted on the award date. The number of potentially dilutive shares related to PSUs is based on the number of shares, if any, that would be issuable at the end of the respective reporting period, assuming that date was the end of the measurement period applicable to such PSUs.
The Predecessor Company issued restricted stock, which are participating securities, and PSUs, and therefore, the Company used the two-class method to calculate earnings per share as shown in the following table (in thousands, except per share amounts):
 
Predecessor
 
April 1, 2017 through April 28, 2017
January 1, 2017 through April 28, 2017
Net income
$
96,936

$
2,660

Less: undistributed income to unvested restricted stock
3,346

120

Undistributed income to common shareholders
93,590

2,540

Basic net income per common share
$
1.88

$
0.05

Diluted net income per common share
$
1.85

$
0.05

 
 
 
Weighted-average shares outstanding - basic
49,902

49,559

Add: dilutive effect of contingent stock awards
584

1,412

Weighted-average shares outstanding - diluted
50,486

50,971

There were 188,278 and 258,126 anti-dilutive shares in the Prior Predecessor Quarter and Prior Predecessor Period, respectively. The participating shareholders are not contractually obligated to share in the losses of the Company; therefore, the entire net loss is allocated to the outstanding common shareholders.

23
Table of Contents

NOTE 13 - INCOME TAXES
On December 22, 2017, the U.S. Congress enacted the Tax Cuts and Jobs Act, which made significant changes to U.S. federal income tax law, including a reduction in the federal corporate tax rate to 21%, effective January 1, 2018. In accordance with U.S. GAAP, we recognized the effect of the rate change on deferred tax assets and liabilities as of December 31, 2017.
The Company uses the asset and liability method of accounting for deferred income taxes. Deferred tax assets and liabilities are determined based on the temporary differences between the financial statement and tax basis of assets and liabilities. Deferred tax assets or liabilities at the end of each period are determined using the tax rate in effect at that time. There is a full valuation allowance on the Company's net deferred tax asset causing the Company’s current rate to differ from the U.S. statutory income tax rate.
As of June 30, 2018, the Company had no unrecognized tax benefits. The Company’s management does not believe that there are any new items or changes in facts or judgments that would impact the Company's tax position taken thus far in 2018.

24
Table of Contents

Item 2.    Management’s Discussion and Analysis of Financial Condition and Results of Operations.
 
The following discussion and analysis of our financial condition and results of operations should be read in conjunction with “Management’s Discussion and Analysis of Financial Condition and Results of Operations” contained in our Annual Report on Form 10-K for the year ended December 31, 2017, as well as the unaudited condensed consolidated financial statements and notes thereto included in this Quarterly Report on Form 10-Q.
Executive Summary 
We are a Denver-based exploration and production company focused on the extraction of oil and associated liquids-rich natural gas in the United States. Our oil and liquids-weighted assets are concentrated primarily in the Wattenberg Field in Colorado and the Dorcheat Macedonia Field in southern Arkansas.
Chief Executive Officer Appointment
Effective April 11, 2018, the Company appointed Eric T. Greager as the new President and Chief Executive Officer of the Company. Mr. Greager has over 20 years of experience in the oil and gas industry, including exposure to both the operating and technical aspects of the industry.
Mr. Greager, 47, previously served as a Vice President and General Manager at Encana Oil & Gas (USA) Inc. Mr. Greager joined Encana in 2006, and served in various management and executive positions, including as a member of the boards of directors of Encana Procurement Inc. and Encana Oil & Gas (USA) Inc. Mr. Greager previously served on the board of directors of Western Energy Alliance and the board of managers of Hunter Ridge Energy Services. Mr. Greager received his Master’s Degree in Economics from the University of Oklahoma and his Bachelor’s Degree in Engineering from the Colorado School of Mines.
Bankruptcy Proceedings under Chapter 11
On January 4, 2017, the Company filed for Chapter 11 in the Bankruptcy Court. The Company received bankruptcy court confirmation of its Plan on April 7, 2017, and emerged from bankruptcy on April 28, 2017, the Effective Date.
Upon emergence from bankruptcy, the Company adopted fresh-start accounting and became a new entity for financial reporting purposes. Upon adoption of fresh-start accounting, our assets and liabilities were recorded at their fair values as of the Effective Date, which differed materially from the recorded values of those same assets and liabilities in the Predecessor Company. The lack of comparability between amounts presented after April 28, 2017 and dates prior thereto are presented with a black line division.
Outlook for 2018
The Company is accelerating its Wattenberg development program while testing enhanced completion designs on large-scale pads throughout the Company’s acreage position, including delineating its French Lake leasehold. The program contemplates running one rig in the first half of 2018 with a second rig added during the third quarter of 2018. The 2018 program is expected to grow Wattenberg annual production by approximately 20% in 2018 and greater than 50% in 2019, assuming a continuous two rig program. Allocated capital associated with this program is expected to be approximately $275.0 million to $295.0 million, which will support drilling 77 gross wells and turning online 49 gross wells in 2018.
    

25
Table of Contents

Results of Operations
The Company conducted standard business operations throughout the bankruptcy proceedings and during the application of fresh-start accounting, resulting in specific financial statement line items following normal course of business trends. The trends associated with the non-impacted financial statement line items are explained throughout the results of operations and include revenues, lease operating expense, gas plant and midstream operating expense, severance and ad valorem taxes, and exploration expense. The financial statement line items that were specifically impacted by the bankruptcy proceedings and application of fresh-start accounting are discussed within the confines of the presented periods and include depreciation, depletion and amortization, general and administrative expense, interest expense, and reorganization items, net.
The following table summarizes our revenues, sales volumes, and average sales prices for the periods indicated:
 
 
Successor
 
 
 
Predecessor
 
 
Three Months Ended June 30, 2018
 
 
April 29, 2017 through June 30, 2017
 
 
 
April 1, 2017 through April 28, 2017
Revenues:
 
 

 
 
 

 
 
 
 
Crude oil sales(1)
$
60,640

 
$
21,016

 
 
$
11,738

Natural gas sales(2)
 
4,629

 
 
3,606

 
 
 
2,075

Natural gas liquids sales (3)
 
6,183

 
 
3,237

 
 
 
2,082

Product revenue
$
71,452

 
$
27,859

 
 
$
15,895

 
 
 
 
 
 
 
 
 
 
Sales Volumes:
 
 
 
 
 
 
 
 
 
Crude oil (MBbls)
 
952.4

 
 
484.3

 
 
 
246.7

Natural gas (MMcf)
 
2,177.8

 
 
1,557.2

 
 
 
828.0

Natural gas liquids (MBbls)
 
324.6

 
 
209.5

 
 
 
108.8

Crude oil equivalent (MBoe)(3)
 
1,640.0

 
 
953.4

 
 
 
493.5

 
 
 
 
 
 
 
 
 
 
Average Sales Prices (before derivatives)(4):
 
 

 
 
 

 
 
 
 
Crude oil (per Bbl)
$
63.67

 
$
43.39

 
 
$
47.58

Natural gas (per Mcf)
$
2.13

 
$
2.32

 
 
$
2.51

Natural gas liquids (per Bbl)
$
19.05

 
$
15.45

 
 
$
19.13

Crude oil equivalent (per Boe)(3)
$
43.57

 
$
29.22

 
 
$
32.21

 
 
 
 
 
 
 
 
 
 
Average Sales Prices (after derivatives)(4):
 
 
 
 
 
 
 
 
 
Crude oil (per Bbl)
$
55.99

 
$
43.39

 
 
$
47.58

Natural gas (per Mcf)
$
2.13

 
$
2.32

 
 
$
2.51

Natural gas liquids (per Bbl)
$
19.05

 
$
15.45

 
 
$
19.13

Crude oil equivalent (per Boe)(3)
$
39.11

 
$
29.22

 
 
$
32.21

_____________________________
(1)
Crude oil sales excludes $0.1 million of oil transportation revenues from third parties, which do not have associated sales volumes, for the Current Successor Quarter and the Prior Successor Quarter. There were no oil transportation revenues from third parties for the Prior Predecessor Quarter.
(2)
Natural gas sales excludes $0.3 million, $0.2 million and $0.1 million of gas gathering revenues from third parties, which do not have associated sales volumes, for the Current Successor Quarter, Prior Successor Quarter and Prior Predecessor Quarter, respectively.
(3)
Determined using the ratio of 6 Mcf of natural gas to 1 Bbl of crude oil.
(4)
The derivatives economically hedge the price we receive for crude oil and natural gas. For the Current Successor Quarter, the derivative cash settlement loss for oil contracts was $7.3 million. Please refer to Note 11 - Derivatives of Part I, Item 1 of this report for additional disclosures.
 
Revenues increased for the Current Successor Quarter by 63%, to $71.5 million, compared to $43.8 million for the combined Prior Successor and Predecessor Quarter, due to a combination of a 44% increase in oil equivalent pricing and a 30% increase in oil sales volumes. In addition to the overall increase due to operations, there was an increase of $1.7 million related

26
Table of Contents

to the adoption of ASC 606, which caused certain revenues to be shown gross compared to a historical net presentation. Please refer to Note 3 - Revenue Recognition of Part I, Item 1 of this report for additional information.

The following table summarizes our operating expenses for the periods indicated:
 
 
Successor
 
 
 
Predecessor
 
 
Three Months Ended June 30, 2018
 
 
April 29, 2017 through June 30, 2017
 
 
 
April 1, 2017 through April 28, 2017
Expenses:
 
 

 
 
 

 
 
 
 
Lease operating expense
$
11,316

 
$
6,153

 
 
$
3,203

Gas plant and midstream operating expense
 
3,247

 
 
1,762

 
 
 
836

Gathering, transportation and processing
 
1,660

 
 
—

 
 
 
—

Severance and ad valorem taxes
 
6,071

 
 
2,408

 
 
 
1,352

Exploration
 
221

 
 
359

 
 
 
292

Depreciation, depletion and amortization
 
9,564

 
 
4,836

 
 
 
6,853

Abandonment and impairment of unproved properties
 
2,477

 
 
—

 
 
 
—

General and administrative
 
9,917

 
 
16,139

 
 
 
2,998

Operating Expenses
$
44,473

 
$
31,657

 
 
$
15,534

 
 
 
 
 
 
 
 
 
 
Selected Costs ($ per Boe):
 
 

 
 
 

 
 
 
 
Lease operating expense
$
6.90

 
$
6.45

 
 
$
6.49

Gas plant and midstream operating expense
 
1.98

 
 
1.85

 
 
 
1.69

Gathering, transportation and processing
 
1.01

 
 
—

 
 
 
—

Severance and ad valorem taxes
 
3.70

 
 
2.53

 
 
 
2.74

Exploration
 
0.13

 
 
0.38

 
 
 
0.59

Depreciation, depletion and amortization
 
5.83

 
 
5.07

 
 
 
13.89

Abandonment and impairment of unproved properties
 
1.51

 
 
—

 
 
 
—

General and administrative
 
6.05

 
 
16.93

 
 
 
6.07

Operating Expenses
$
27.11

 
$
33.21

 
 
$
31.47

Lease operating expense.  Our lease operating expense increased $2.0 million, or 21%, to $11.3 million for the Current Successor Quarter from $9.4 million for the combined Prior Successor and Predecessor Quarter, and increased on an equivalent basis per Boe by 7%. The Company experienced a $0.4 million increase in pumping and gauging charges, $0.4 million increase in well servicing charges, and $0.7 million increase in compression charges during the Current Successor Quarter when compared to the combined Prior Successor and Predecessor Quarter. The increase in costs is largely associated with the accelerated schedule of compressor exchanges within our Rocky Mountain region.
Gas plant and midstream operating expense.  Our gas plant and midstream operating expense increased $0.6 million, or 25%, to $3.2 million for the Current Successor Quarter from $2.6 million for the combined Prior Successor and Predecessor Quarter. Gas plant and midstream operating expense per Boe increased 10% during the comparable periods due to the costs associated with the accelerated schedule of compressor exchanges within our Rocky Mountain Infrastructure gathering systems.
Gathering, transportation and processing.  As noted in the operating revenues section above, the increase in gathering, transportation and processing expense during the Current Successor Quarter to $1.7 million is related to the Company's adoption of ASC 606 during the Current Successor Period, which caused certain revenues to be shown gross, with the related expenses recorded in this line item. Please refer to Note 3 - Revenue Recognition of Part I, Item 1 of this report for additional information.
Severance and ad valorem taxes.  Our severance and ad valorem taxes increased 61% to $6.1 million for the Current Successor Quarter from $3.8 million for the combined Prior Successor and Predecessor Quarter. Severance and ad valorem taxes primarily correlate to revenues, which increased 63% over the comparable period. 

27
Table of Contents

Exploration. Our exploration expense for the Current Successor Quarter, Prior Successor Quarter, and Prior Predecessor Quarter consisted primarily of delay lease rental payments.
 Depreciation, depletion and amortization.  Our depreciation, depletion and amortization expense per Boe was $5.83, $5.07 and $13.89 for the Current Successor Quarter, Prior Successor Quarter, and Prior Predecessor Quarter, respectively. The Prior Successor Quarter reflects the $310.6 million fair value downward adjustment to the depletable asset base upon adoption of fresh-start accounting. The Current Successor Quarter excludes depreciation, depletion and amortization on the assets held for sale. The increase in depreciation, depletion and amortization during the Current Successor Quarter when compared to the Prior Successor Quarter primarily correlates to an increase in capital expenditures.
Abandonment and impairment of unproved properties.  The Company incurred $2.5 million of impairment charges due to the standard amortization of unproved properties within the Wattenberg Field during the Current Successor Quarter. There were no abandonment and impairment of unproved properties during the Prior Successor and Predecessor Quarters.
General and administrative. Our general and administrative expense decreased by $9.2 million to $9.9 million for the Current Successor Quarter from $19.1 million for the combined Prior Successor and Predecessor Quarter. On a per Boe basis, our general and administrative expense was $6.05 in the Current Successor Quarter as compared to $13.23 in the combined Prior Successor and Predecessor Quarter. The Prior Successor Quarter reflects a one-time $7.1 million non-cash stock-based compensation charge from the vesting of the Company's former Chief Executive Officer's stock awards upon separation from the Company. The incremental decrease in general and administrative expense during the Current Successor Quarter when compared to the combined Prior Successor and Predecessor Quarter, is due to a $1.1 million decrease in salaries and benefits due to workforce reductions and a $1.0 million decrease in restructuring fees.

Derivative loss.  Our derivative loss for the Current Successor Quarter was $22.0 million. We had no derivative contracts during the Prior Successor and Predecessor Quarters. Our derivative loss is due to settlements and fair market value adjustments caused by market prices being higher than our contracted hedge prices. Please refer to Note 11 - Derivatives of Part I, Item 1 of this report for additional discussion.
 Interest expense.  Our interest expense for the Current Successor Quarter, the Prior Successor Quarter, and the Prior Predecessor Quarter was $0.8 million, $0.2 million, and $1.1 million, respectively. Upon filing its petition for Chapter 11, the Company ceased accruing interest expense on its Senior Notes. The Company incurred $0.6 million in interest expense associated with the credit facility and $0.2 million in commitment fees on the available borrowing base under the credit facility during the Current Successor Quarter. The Company incurred $0.2 million in commitment fees on the available borrowing base under the credit facility during the Prior Successor Quarter. The interest expense incurred during the Prior Predecessor Quarter relates to the predecessor credit facility. Average debt outstanding for the Current Successor Quarter and the Prior Predecessor Quarter was $45.6 million and $305.1 million, respectively. The Company had no outstanding debt for the Prior Successor Quarter.
Reorganization items, net. The Company incurred significant costs associated with the reorganization. Our reorganization income was $97.8 million for the Prior Predecessor Quarter. Upon adoption of fresh-start accounting, the Company incurred a $412.9 million gain on the settlement of liabilities subject to compromise, a $311.4 million loss on fresh-start valuation adjustments, and $3.7 million for professional fees and other charges.



28
Table of Contents

The following table summarizes our revenues, sales volumes, and average sales prices for the periods indicated:
 
 
Successor
 
 
 
Predecessor
 
 
Six Months Ended June 30, 2018
 
 
April 29, 2017 through June 30, 2017
 
 
 
January 1, 2017 through April 28, 2017
Revenues:
 
 

 
 
 

 
 
 
 
Crude oil sales(1)
$
112,479

 
$
21,016

 
 
$
51,593

Natural gas sales(2)
 
10,563

 
 
3,606

 
 
 
8,584

Natural gas liquids sales
 
12,191

 
 
3,237

 
 
 
7,867

Product revenue
$
135,233

 
$
27,859

 
 
$
68,044

 
 
 
 
 
 
 
 
 
 
Sales Volumes:
 
 
 
 
 
 
 
 
 
Crude oil (MBbls)
 
1,847.8

 
 
484.3

 
 
 
1,068.5

Natural gas (MMcf)
 
4,313.0

 
 
1,557.2

 
 
 
3,336.1

Natural gas liquids (MBbls)
 
582.2

 
 
209.5

 
 
 
449.0

Crude oil equivalent (MBoe)(3)
 
3,148.8

 
 
953.4

 
 
 
2,073.5

 
 
 
 
 
 
 
 
 
 
Average Sales Prices (before derivatives)(4):
 
 

 
 
 

 
 
 
 
Crude oil (per Bbl)
$
60.87

 
$
43.39

 
 
$
48.29

Natural gas (per Mcf)
$
2.45

 
$
2.32

 
 
$
2.57

Natural gas liquids (per Bbl)
$
20.94

 
$
15.45

 
 
$
17.52

Crude oil equivalent (per Boe)(3)
$
42.95

 
$
29.22

 
 
$
32.82

 
 
 
 
 
 
 
 
 
 
Average Sales Prices (after derivatives)(4):
 
 
 
 
 
 
 
 
 
Crude oil (per Bbl)
$
54.47

 
$
43.39

 
 
$
48.29

Natural gas (per Mcf)
$
2.50

 
$
2.32

 
 
$
2.57

Natural gas liquids (per Bbl)
$
20.94

 
$
15.45

 
 
$
17.52

Crude oil equivalent (per Boe)(3)
$
39.26

 
$
29.22

 
 
$
32.82

_____________________________
(1)
Crude oil sales excludes $0.2 million, $0.1 million, and $0.1 million of oil transportation revenues from third parties, which do not have associated sales volumes, for the Current Successor Period, Prior Successor Period and Prior Predecessor Period, respectively.
(2)
Natural gas sales excludes $0.6 million, $0.2 million, and $0.4 million of gas gathering revenues from third parties, which do not have associated sales volumes, for the Current Successor Period, Prior Successor Period and Prior Predecessor Period, respectively.
(3)
Determined using the ratio of 6 Mcf of natural gas to 1 Bbl of crude oil.
(4)
The derivatives economically hedge the price we receive for crude oil. For the Current Successor Period, the derivative cash settlement loss for oil contracts was $11.8 million and the derivative cash settlement gain for natural gas contracts was $0.2 million. Please refer to Note 11 - Derivatives of Part I, Item 1 of this report for additional disclosures.
Revenues increased for the Current Successor Period by 41%, to $135.2 million, compared to $95.9 million for the combined Prior Successor and Predecessor Period, due to a combination of a 36% increase in oil equivalent pricing and a 4.0% increase in sales volumes. In addition to the overall increase due to operations, there was an increase of $4.0 million related to the adoption of ASC 606, which caused certain revenues to be shown gross compared to a historical net presentation. Please refer to Note 3 - Revenue Recognition of Part I, Item 1 of this report for additional information.

29
Table of Contents

The following table summarizes our operating expenses for the periods indicated:
 
 
Successor
 
 
 
Predecessor
 
 
Six Months Ended June 30, 2018
 
 
April 29, 2017 through June 30, 2017
 
 
 
January 1, 2017 through April 28, 2017
Expenses:
 
 

 
 
 

 
 
 
 
Lease operating expense
$
21,775

 
$
6,153

 
 
$
13,128

Gas plant and midstream operating expense
 
6,860

 
 
1,762

 
 
 
3,541

Gathering, transportation and processing
 
3,998

 
 
—

 
 
 
—

Severance and ad valorem taxes
 
11,303

 
 
2,408

 
 
 
5,671

Exploration
 
250

 
 
359

 
 
 
3,699

Depreciation, depletion and amortization
 
17,072

 
 
4,836

 
 
 
28,065

Abandonment and impairment of unproved properties
 
4,979

 
 
—

 
 
 
—

Unused commitments
 
21

 
 
—

 
 
 
993

General and administrative
 
19,451

 
 
16,139

 
 
 
15,092

Operating Expenses
$
85,709

 
$
31,657

 
 
$
70,189

 
 
 
 
 
 
 
 
 
 
Selected Costs ($ per Boe):
 
 

 
 
 

 
 
 
 
Lease operating expense
$
6.92

 
$
6.45

 
 
$
6.33

Gas plant and midstream operating expense
 
2.18

 
 
1.85

 
 
 
1.71

Gathering, transportation and processing
 
1.27

 
 
—

 
 
 
—

Severance and ad valorem taxes
 
3.59

 
 
2.53

 
 
 
2.73

Exploration
 
0.08

 
 
0.38

 
 
 
1.78

Depreciation, depletion and amortization
 
5.42

 
 
5.07

 
 
 
13.54

Abandonment and impairment of unproved properties
 
1.58

 
 
—

 
 
 
—

Unused commitments
 
0.01

 
 
—

 
 
 
0.48

General and administrative
 
6.18

 
 
16.93

 
 
 
7.28

Operating Expenses
$
27.23

 
$
33.21

 
 
$
33.85

 
Lease operating expense.  Our lease operating expense increased $2.5 million, or 13%, to $21.8 million for the Current Successor Period from $19.3 million for the combined Prior Successor and Predecessor Period, and increased on an equivalent basis to $6.92 per Boe from $6.37 per Boe. The Company experienced a $0.8 million increase in pumping and gauging charges, $0.5 million increase in compression charges, and $1.2 million increase in well servicing charges during the Current Successor Period when compared to the same period in 2017. The increase in costs is largely associated with the accelerated schedule of compressor exchanges within our Rocky Mountain region.

Gas plant and midstream operating expense.  Our gas plant and midstream operating expense increased $1.6 million, or 29%, to $6.9 million for the Current Successor Period from $5.3 million for the Prior Successor and Predecessor Period. Gas plant and midstream operating expense per Boe increased 25% during the comparable periods due to the costs associated with the accelerated schedule of compressor exchanges within our Rocky Mountain Infrastructure gathering systems.
Gathering, transportation and processing.  As noted in the operating revenues section above, the increase to gathering, transportation and processing expense during the Current Successor Period to $4.0 million is related to the Company's adoption of ASC 606 during the Current Successor Period, which caused certain revenues to be shown gross, with the related expenses recorded in this line item. Please refer to Note 3 - Revenue Recognition of Part I, Item 1 of this report for additional information.

Severance and ad valorem taxes.  Our severance and ad valorem taxes increased 40% to $11.3 million for the Current Successor Period from $8.1 million for the combined Prior Successor and Predecessor Period. Severance and ad valorem taxes primarily correlate to revenue, which increased 41% over the comparable period. 


30
Table of Contents

 Exploration.  Our exploration expense of $0.3 million during the Current Successor Period was due to delay rental payments. Exploration expense of $4.1 million during the combined Prior Successor and Predecessor Period was due to $0.7 million of seismic charges for data within our Wattenberg Field, a write-off of $3.0 million for abandoned location costs within our Dorcheat Macedonia and Wattenberg Fields, and $0.4 million in delay lease rental payments.
 
Depreciation, depletion and amortization.  Our depreciation, depletion and amortization expense per Boe was $5.42, $5.07, and $13.54 for the Current Successor Period, the Prior Successor Period, and Prior Predecessor Period, respectively. The Prior Successor Periods reflect the $310.6 million fair value downward adjustment to the depletable asset base upon adoption of fresh-start accounting. The Current Successor Period excludes depreciation, depletion and amortization on the assets held for sale. The increase in depreciation, depletion and amortization during the Current Successor Period when compared to the Prior Successor Period primarily correlates to an increase in capital expenditures.
Abandonment and impairment of unproved properties.  The Company incurred $5.0 million of impairment charges relating to non-core leases expiring and the standard amortization of unproved properties within the Wattenberg Field during the Current Successor Period. There were no abandonment and impairment of unproved properties during the Prior Successor and Predecessor Periods.
Unused commitments. We incurred minimal unused commitment fees during the Current Successor Period. There were no unused commitments during the Prior Successor Period. During the Prior Predecessor Period, we incurred $1.0 million in unused commitment fees on a water supply contract in the Wattenberg Field.
 
General and administrative. Our general and administrative expense decreased by $11.7 million to $19.5 million for the Current Successor Period from $31.2 million for the combined Prior Successor and Predecessor Period. On a per Boe basis our general and administrative expense was $6.18 for the Current Successor Period and $10.32 on the combined Prior Successor and Predecessor Period. The Prior Successor Period reflects a one-time $7.1 million non-cash stock-based compensation charge from the vesting of the Company's former Chief Executive Officer's stock awards upon separation from the Company, and when adjusted for the one-time charge, the combined Prior Successor and Predecessor Period was $7.96 on a per Boe basis. The incremental decrease in general and administrative expense during the Current Successor Period, when compared to the combined Prior Successor and Predecessor Periods, is due to a $2.7 million decrease in salaries and benefits due to workforce reductions, $0.7 million decrease in advisor fees, and $0.6 million decrease in office rent due to negotiations during bankruptcy.
 
Derivative loss.  Our derivative loss for the Current Successor Period was $30.8 million. We had no derivative contracts during the Prior Successor or Predecessor Periods. Our derivative loss is due to settlements and fair market value adjustments caused by market prices being higher than our contracted hedge prices. Please refer to Note 11 - Derivatives above for additional discussion.
 
Interest expense.  Our interest expense for the Current Successor Period, the Prior Successor Period, and the Prior Predecessor Period was $1.2 million, $0.2 million, and $5.7 million, respectively. Upon filing its petition for Chapter 11, the Company ceased accruing interest expense on its Senior Notes. The Company incurred $0.8 million in interest expense associated with the credit facility and $0.4 million in commitment fees on the available borrowing base under the credit facility during the Current Successor Period. The Company incurred $0.2 million in commitment fees on the available borrowing base under the credit facility during the Prior Successor Period. Interest expense on the Senior Notes was $1.0 million for the Prior Predecessor Period, with the remaining interest expense relating to the predecessor credit facility. Average debt outstanding for the Current Successor Period and the Prior Predecessor Period was $28.1 million and $657.5 million, respectively. The Company had no outstanding debt during the Prior Successor Period.

Reorganization items, net. Our reorganization income was $8.8 million for the Prior Predecessor Period. Upon filing its petition for Chapter 11, the Company incurred a $51.2 million make-whole payment on the Senior Notes, incurred $31.7 million in legal and professional fees, and wrote-off $6.2 million of debt issuance and premium costs on the Senior Notes. Upon adoption of fresh-start accounting, the Company incurred a $412.9 million gain on settlement of liabilities subject to compromise, a $311.4 million loss on fresh-start valuation adjustments, and $3.7 million for professional fees and other charges.

Liquidity and Capital Resources
The Company's anticipated sources of liquidity include cash from operating activities, borrowings under the credit facility, proceeds from sales of assets, and potential proceeds from capital and debt market transactions. Our cash flows from operating activities are subject to significant volatility due to changes in commodity prices for our crude oil, NGLs, and natural

31
Table of Contents

gas products, as well as variations in our production. The prices for these commodities are driven by a number of factors beyond our control, including global and regional product supply and demand, weather, product distribution, refining and processing capacity, and other supply chain dynamics, among other factors. To mitigate some of the pricing risk, we have 49% of our 2018 guided production hedged as of June 30, 2018 and as of the filing date of this report.
As of June 30, 2018, our liquidity was $153.7 million, consisting of cash on hand of $22.0 million and $131.7 million of available borrowing capacity on the credit facility. Please refer to Note 6 - Long-term Debt in Part I, Item 1 above for additional discussion.
We anticipate investing approximately $275.0 million to $295.0 million, which will support drilling 77 gross wells and turning online 49 gross wells in 2018.
Our weighted-average interest rates on borrowings from the credit facility was 5.12% for the Current Successor Period.
The following table summarizes our cash flows and other financial measures for the periods indicated (in thousands):
 
Successor
 
 
Predecessor
 
Six Months Ended June 30, 2018
 
April 29, 2017 through June 30, 2017
 
 
January 1, 2017 through April 28, 2017
Net cash provided by (used in) operating activities
$
42,149

 
$
(3,833
)
 
 
$
(19,884
)
Net cash used in investing activities
(93,037
)
 
(10,056
)
 
 
(6,022
)
Net cash provided by (used in) financing activities
60,174

 
(2,080
)
 
 
15,406

Cash, cash equivalents and restricted cash
22,068

 
52,437

 
 
68,406

Acquisition of oil and gas properties
1,295

 
4,982

 
 
445

Exploration and development of oil and gas properties
91,482

 
4,913

 
 
5,123

Cash flows provided by (used in) operating activities
 The Current Successor Period and the Prior Successor Period included cash receipts and disbursements attributable to our normal operating cycle. The Prior Predecessor Period contained reorganization costs along with our normal operating receipts and disbursements. See Results of Operations above for more information on the factors driving these changes.
Cash flows used in investing activities
Expenditures for development of oil and natural gas properties are the primary use of our capital resources. The Company spent $92.8 million, $9.9 million, and $5.6 million on the exploration, development, and acquisition of oil and gas properties during the Current Successor Period, Prior Successor Period, and Prior Predecessor Period, respectively. The increase in capital expenditures among the periods is a direct result of emerging from bankruptcy and resuming development operations.
Cash flows provided by (used in) financing activities
Net cash provided by financing activities for the Current Successor Period is due to drawing $60.0 million on our credit facility. Net cash used in financing activities for the Prior Successor Period consisted of $2.1 million for employee tax withholdings in exchange for the return of common stock. Net cash provided by financing activities for the Prior Predecessor Period consisted of proceeds from the rights offering of $207.5 million net of the $191.7 million repayment to the predecessor revolving credit facility.
New Accounting Pronouncements 
Please refer to Note 2 — Basis of Presentation under Part I, Item 1 of this report for any recently issued or adopted accounting standards.
Critical Accounting Policies and Estimates
Information regarding our critical accounting policies and estimates is contained in Part II, Item 7 of our 2017 Form 10-K. 
Effects of Inflation and Pricing

32
Table of Contents

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.
Contractual Obligations
There have been no significant changes from our 2017 Form 10-K in our obligations and commitments. Please refer to Note 7 - Commitments and Contingencies under Part I, Item 1 of this report for additional discussion.
Cautionary Note Regarding Forward-Looking Statements
This Quarterly Report on Form 10-Q contains various statements, including those that express belief, expectation or intention, as well as those that are not statements of historic fact, that are forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities and Exchange Act of 1934, as amended (the “Exchange Act”). When used in this Quarterly Report on Form 10-Q, the words “could,” “believe,” “anticipate,” “intend,” “estimate,” “expect,” “may,” “continue,” “predict,” “potential,” “project,” “plan,” “will,” and similar expressions are intended to identify forward-looking statements, although not all forward-looking statements contain such identifying words. These forward-looking statements are based on management's current belief, based on currently available information, as to the outcome and timing of future events.
Forward‑looking statements include statements related to, among other things:
•
the Company's business strategies and intent to maximize liquidity;
•
reserves estimates;
•
estimated sales volumes;
•
amount and allocation of forecasted capital expenditures and plans for funding capital expenditures and operating expenses;
•
ability to modify future capital expenditures;
•
the Wattenberg Field being a premier oil and resource play in the United States;
•
anticipated costs;
•
compliance with debt covenants;
•
ability to fund and satisfy obligations related to ongoing operations;
•
compliance with government regulations, including environmental, health, and safety regulations and liabilities thereunder;
•
adequacy of gathering systems and continuous improvement of such gathering systems;
•
impact from the lack of available gathering systems and processing facilities in certain areas;
•
natural gas, oil, and natural gas liquid prices and factors affecting the volatility of such prices;
•
impact of lower commodity prices;
•
sufficiency of impairments;
•
the ability to use derivative instruments to manage commodity price risk and ability to use such instruments in the future;

33
Table of Contents

•
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 and C benches in our legacy acreage;
•
our ability to replace oil and natural gas reserves;
•
our ability to convert PUDs to producing properties within five years of their initial proved booking;
•
impact of recently issued accounting pronouncements;
•
impact of the loss a single customer or any purchaser of our products;
•
timing and ability to meet certain volume commitments related to purchase and transportation agreements;
•
the impact of customary royalty interests, overriding royalty interests, obligations incident to operating agreements, liens for current taxes, and other industry-related constraints;
•
our financial position;
•
our cash flow and liquidity;
•
the adequacy of our insurance; and
•
other statements concerning our operations, economic performance, and financial condition.
We have based these forward-looking statements on certain assumptions and analyses we have made in light of our experience and our perception of historical trends, current conditions, and expected future developments as well as other factors we believe are appropriate under the circumstances. They can be affected by inaccurate assumptions or by known or unknown risks and uncertainties. Many such factors will be important in determining actual future results. The actual results or developments anticipated by these forward-looking statements are subject to a number of risks and uncertainties, many of which are beyond our control, and may not be realized or, even if substantially realized, may not have the expected consequences. Actual results could differ materially from those expressed or implied in the forward-looking statements. 
Factors that could cause actual results to differ materially include, but are not limited to, the following: 
•
the risk factors discussed in Part I, Item 1A of our Annual Report on Form 10-K for the year ended December 31, 2017;
•
further declines or volatility in the prices we receive for our oil, natural gas liquids, and natural gas;
•
general economic conditions, whether internationally, nationally or in the regional and local market areas in which we do business;
•
ability of our customers to meet their obligations to us;
•
our access to capital;

34
Table of Contents

•
our ability to generate sufficient cash flow from operations, borrowings, or other sources to enable us to fully develop our undeveloped acreage positions;
•
the presence or recoverability of estimated oil and natural gas reserves and the actual future sales volume rates and associated costs;
•
uncertainties associated with estimates of proved oil and gas reserves;
•
the possibility that the industry may be subject to future local, state, and federal regulatory or legislative actions (including additional taxes and changes in environmental regulation);
•
environmental risks;
•
seasonal weather conditions;
•
lease stipulations;
•
drilling and operating risks, including the risks associated with the employment of horizontal drilling techniques;
•
our ability to acquire adequate supplies of water for drilling and completion operations;
•
availability of oilfield equipment, services, and personnel;
•
exploration and development risks;
•
competition in the oil and natural gas industry;
•
management’s ability to execute our plans to meet our goals;
•
our ability to attract and retain key members of our senior management and key technical employees;
•
our ability to maintain effective internal controls;
•
access to adequate gathering systems and pipeline take-away capacity;
•
our ability to secure firm transportation for oil and natural gas we produce and to sell the oil and natural gas at market prices;
•
costs and other risks associated with perfecting title for mineral rights in some of our properties;
•
continued hostilities in the Middle East and other sustained military campaigns or acts of terrorism or sabotage; and
•
other economic, competitive, governmental, legislative, regulatory, geopolitical, and technological factors that may negatively impact our businesses, operations, or pricing.
All forward-looking statements speak only as of the date of this report. We disclaim any obligation to update or revise these statements unless required by law, and you should not place undue reliance on these forward-looking statements. Although we believe that our plans, intentions, and expectations reflected in or suggested by the forward-looking statements we make in this report are reasonable, we can give no assurance that these plans, intentions, or expectations will be achieved. We disclose important factors that could cause our actual results to differ materially from our expectations under Part II, Item 1A. Risk Factors and Part I, Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations and elsewhere in this report. These cautionary statements qualify all forward-looking statements attributable to us or persons acting on our behalf. 

35
Table of Contents

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 use of financial instruments may expose us to the risk of financial loss in certain circumstances, including instances when (1) sales volumes are less than expected requiring market purchases to meet commitments, or (2) our counterparties fail to purchase the contracted quantities of oil or otherwise fail to perform. To the extent that we engage in derivative contracts, we may be prevented from realizing the benefits of favorable price changes in the physical market. However, we are similarly insulated against decreases in such prices.
As of June 30, 2018, and through the filing date of this report, all of our derivative arrangements are concentrated with four counterparties, all of which are lenders under our credit facility. If these counterparties fail to perform their obligations, we may suffer financial loss or be prevented from realizing the benefits of favorable price changes in the physical market.
The result of oil market prices exceeding our swap prices requires us to make payment for the settlement of our derivatives, if owed by us, generally up to 15 business days before we receive market price cash payments from our customers. This could have a material adverse effect on our cash flows for the period between derivative settlement and payment for revenues earned.
Interest Rates 
As of June 30, 2018, we had $60.0 million outstanding under our credit facility. Borrowings under our credit facility bear interest at a fluctuating rate that is tied to an adjusted Base Rate or London Interbank Offered Rate, at our option. Any increases in these interest rates can have an adverse impact on our results of operations and cash flow. As of June 30, 2018, and through the filing date of this report, the Company was in compliance with all financial and non-financial covenants.
Counterparty and Customer Credit Risk 
In connection with our derivatives activity, we have exposure to financial institutions in the form of derivative transactions. Four lenders under our successor credit facility are currently counterparties on our derivative instruments currently in place and have investment grade credit ratings.
We are also subject to credit risk due to concentration of our oil and natural gas receivables with certain significant customers. The inability or failure of our significant customers to meet their obligations to us or their insolvency or liquidation may adversely affect our financial results. We review the credit rating, payment history and financial resources of our customers, but we do not require our customers to post collateral.
Marketability of Our Production 
The marketability of our production from the Mid-Continent and Rocky Mountain regions depends in part upon the availability, proximity and capacity of third-party refineries, access to regional trucking, pipeline and rail infrastructure, natural gas gathering systems, and processing facilities. We deliver crude oil and natural gas produced from these areas through trucking services, and pipelines that we do not own. The lack of availability or capacity on these systems and facilities could

36
Table of Contents

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, 2017.
Item 4.    Controls and Procedures.
Evaluation of Disclosure Controls and Procedures 
Our management, with the participation of our principal executive officer and principal financial officer, evaluated the effectiveness of our disclosure controls and procedures as of June 30, 2018. The term “disclosure controls and procedures,” as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act, means controls and other procedures of a company that are designed to ensure that information required to be disclosed by a company in the reports that it files or submits under the Exchange Act is recorded, processed, summarized, and reported, within the time periods specified in SEC rules and forms. Disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed by a company in the reports that it files or submits under the Exchange Act is accumulated and communicated to the company’s management, including its principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure. Based on the evaluation of our disclosure controls and procedures as of June 30, 2018, our principal executive officer and principal financial officer concluded that, as of such date, our disclosure controls and procedures were effective at the reasonable assurance level. 
Management recognizes that any controls and procedures, no matter how well designed and operated, can provide only reasonable assurance of achieving their objectives, and management necessarily applies its judgment in evaluating the cost-benefit relationship of possible controls and procedures. To assist management, we have established an internal audit function to verify and monitor our internal controls and procedures. The Company’s internal control system is supported by written policies and procedures, contains self-monitoring mechanisms and is audited by the internal audit function. Appropriate actions are taken by management to correct deficiencies as they are identified.
Changes in Internal Control over Financial Reporting 
There were no changes in our internal control over financial reporting identified in management’s evaluation pursuant to Rules 13a-15(d) or 15d-15(d) of the Exchange Act during the quarter ended June 30, 2018 that materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
PART II - OTHER INFORMATION
 
Item 1.   Legal Proceedings.
From time to time, we are subject to legal proceedings and claims that arise in the ordinary course of business. Like other oil and gas producers and marketers, our operations are subject to extensive and rapidly changing federal and state environmental, health, and safety and other laws and regulations governing air emissions, wastewater discharges, and solid and hazardous waste management activities. As of the date of this filing, there are no material pending or overtly threatened legal actions against us of which we are aware.
As previously described in our 2017 Form 10-K, the Company and the CDPHE agreed to a COC resolving the matters addressed by a compliance advisory issued to the Company for certain storage tank facilities located in the Wattenberg Field with respect to applicable air quality regulations. Pursuant to the terms of the COC, the Company paid an administrative penalty of $0.2 million in 2017. The Company must also adopt procedures and processes to address the monitoring, reporting, and control of air emissions. The COC further sets forth compliance requirements and criteria for continued operations and contains provisions regarding record-keeping, modifications to the COC, circumstances under which the COC may terminate with respect to certain wells and facilities, and the sale or transfer of operational or ownership interests covered by the COC. In order to be in compliance, the Company incurred $0.7 million in 2017, and currently anticipates spending $3.5 million in 2018,

37
Table of Contents

and $3.1 million for 2019 through 2022. The COC can be terminated after four years with a showing of substantial compliance and CDPHE approval.
There have been no other material changes to our legal proceedings from those described in our Annual Report on Form 10-K for the year ended December 31, 2017.
Item 1A. Risk Factors.
Our business faces many risks. Any of the risk factors discussed in this report or our other SEC filings could have a material impact on our business, financial position or results of operations. Additional risks and uncertainties not presently known to us or that we currently believe to be immaterial may also impair our business operation. For a discussion of our potential risks and uncertainties, see the risk factors in Part I, Item 1A in our Annual Report on Form 10-K for the year ended December 31, 2017, together with other information in this report and other reports and materials we file with the SEC. We have identified these risk factors as important factors that could cause our actual results to differ materially from those contained in any written or oral forward-looking statements made by us or on our behalf.
Item 2.    Unregistered Sales of Equity Securities and Use of Proceeds.
Unregistered sales of securities. There were no sales of unregistered equity securities during the three month period ended June 30, 2018.
 Issuer purchases of equity securities.  The following table contains information about acquisitions of our equity securities during the three month period ended June 30, 2018:
 
 
 
 
 
 
 
Maximum 
 
 
 
 
 
Total Number of 
 
Number of
 
Total
 
 
 
Shares
 
Shares that May 
 
Number of
 
Average Price
 
Purchased as Part of
 
Be Purchased
 
Shares
 
Paid per
 
Publicly Announced
 
Under Plans or 
 
Purchased(1)
 
Share
 
Plans or Programs
 
Programs
April 1, 2018 - April 30, 2018
18,667

 
$
29.12

 
—

 
—

May 1, 2018 - May 31, 2018
5,346

 
$
35.61

 
—

 
—

June 1, 2018 - June 30, 2018
—

 
$
—

 
—

 
—

Total
24,013

 
$
30.56

 
—

 
—

____________________________________________________________________________
(1)
Represents shares that employees surrendered back to us that equaled in value the amount of taxes required for payroll tax withholding obligations upon the vesting of equity awards under the 2017 LTIP. These repurchases were not part of a publicly announced plan or program to repurchase shares of our common stock, nor do we have a publicly announced plan or program to repurchase shares of our common stock.
Our new revolving credit facility provides for restrictions on the payment of dividends.
Item 3. Defaults Upon Senior Securities.
None
Item 4. Mine Safety Disclosures.
Not applicable.
Item 5. Other Information.
The information set forth below is included herein for the purpose of providing the disclosure required under “Item 2.01, Completion of Acquisition or Disposition of Assets” of Current Report on Form 8-K.
As previously announced by the Company in its Current Report on Form 8-K filed with the SEC on August 7, 2018, the Company, through its wholly owned subsidiary Bonanza Creek Energy Operating Company, LLC (“BCEOC”), closed on the sale of BCEOC’s equity interests in certain of its subsidiaries to Mission Creek Resources, LLC (“Buyer”) on August 6, 2018 under the Membership Interest Purchase Agreement between BCEOC and Buyer dated August 6, 2018 (the “Agreement”). BCEOC sold its equity interests in Bonanza Creek Energy Resources, LLC (“BCER”), which in turn owns all of the outstanding equity interest in Bonanza Creek Energy Upstream LLC (“BCEU”) and Bonanza Creek Energy Midstream,

38
Table of Contents

LLC (“BCEM” and together with BCER and BCEU, the “Equity Companies”). The Equity Companies' assets include oil and gas wells, leases, and other associated assets and interests in the Dorcheat Macedonia and McKamie Patton Fields in southern Arkansas, along with gas processing facilities located in Lafayette and Columbia counties in Arkansas (collectively, the “Mid-Con Assets”). Net consideration received by the Company was $102.9 million after customary preliminary closing adjustments resulting in an approximate gain of $30.5 million at the time of closing. The transaction was effective as of February 1, 2018.
A copy of the Agreement was filed within the Current Report on Form 8-K filed on August 7, 2018, and is incorporated herein by reference. The summary of the material terms of the Agreement does not purport to be a complete description thereof and is qualified in its entirety by the full text of the Agreement, which was attached as Exhibit 99.2 to the Current Report on Form 8-K filed on August 7, 2018, and is incorporated herein by reference. The Agreement was included to provide investors and security holders with information regarding its terms. It is not intended to provide any other factual information about the parties thereto. The representations and warranties of each party set forth in the Agreement were made solely for the benefit of the other party to the Agreement and such representations and warranties should not be relied on by any other person. In addition, such representations and warranties (i) have been qualified by disclosures made to the other party thereto, (ii) are subject to the materiality standards contained in the Agreement which may differ from what may be viewed as material by investors, and (iii) were made only as of the date of the Agreement or such other date as is specified in the Agreement.
The following pro forma condensed consolidated balance sheet information as of June 30, 2018 is based on the historical financial statements of the Company, including certain pro forma adjustments, and has been prepared to illustrate the pro forma effect of the Company’s sale of the Mid-Con Assets on August 6, 2018 as if the sale had occurred on June 30, 2018.
The unaudited pro forma consolidated statements of income for the three and six months ended June 30, 2018 and the year ended December 31, 2017 are based on the historical financial statements of the Company, including certain pro forma adjustments, and assume that the sale of the Mid-Con Assets occurred as of the beginning of the periods presented.
The unaudited pro forma condensed consolidated financial information has been prepared based upon available information and management estimates; actual amounts may differ from these estimated amounts. In preparing the pro forma information, the Company eliminated all direct expenses related to the properties but did not adjust for commodity hedges or general and administrative expenses. The unaudited pro forma condensed combined financial information is for informational purposes only and is not intended to represent or be indicative of the results of operations or financial position of the Company or the pro forma effect of closing of the divestiture and should not be taken as indicative of the Company’s future results of operations or financial position. Actual results may differ significantly from those reflected in the unaudited pro forma financial information for a number of reasons, including, but not limited to, differences between the assumptions used to prepare the unaudited pro forma combined financial information and actual results. The pro forma adjustments are described in the Notes to the Unaudited Pro Forma Condensed Consolidated Financial Statements.

The unaudited pro forma condensed consolidated financial information should be read in conjunction with the financial statements and notes and related Management’s Discussion and Analysis of Financial Condition and Results of Operations included within this quarterly report and in the Company’s Annual Report on Form 10-K for the year ended December 31, 2017.














39
Table of Contents

BONANZA CREEK ENERGY, INC. AND SUBSIDIARIES
PRO FORMA CONDENSED CONSOLIDATED BALANCE SHEETS (UNAUDITED)
(in thousands, except share amounts)
 
Historical
 
Pro Forma
 
 
Unaudited Pro Forma Balance Sheet
 
June 30, 2018
 
Adjustments
 
 
June 30, 2018
ASSETS
 

 
 
 
 
 

Current assets:
 

 
 
 
 
 

Cash and cash equivalents
$
21,989

 
$
42,933

(a)
 
$
64,922

Accounts receivable:
 

 
 
 
 


Oil and gas sales
38,830

 
—

 
 
38,830

Joint interest and other
13,926

 
—

 
 
13,926

Prepaid expenses and other
5,620

 
(207
)
(b)
 
5,413

Inventory of oilfield equipment
1,434

 
(386
)
(b)
 
1,048

Derivative assets
39

 
—

 
 
39

Total current assets
81,838

 
42,340

 
 
124,178

Property and equipment (successful efforts method):
 

 
 
 
 


Proved properties
552,858

 
—

 
 
552,858

Less: accumulated depreciation, depletion and amortization
(29,703
)
 
—

 
 
(29,703
)
Total proved properties, net
523,155

 
—

 
 
523,155

Unproved properties
179,735

 
—

 
 
179,735

Wells in progress
52,747

 
—

 
 
52,747

Oil and gas properties held for sale, net of accumulated depreciation, depletion and amortization
82,328

 
(82,328
)
(b)
 
—

Other property and equipment, net of accumulated depreciation
4,488

 
(425
)
(b)
 
4,063

Total property and equipment, net
842,453

 
(82,753
)
 
 
759,700

Long-term derivative assets
—

 
—

 
 
—

Other noncurrent assets
3,151

 
—

 
 
3,151

Total assets
$
927,442

 
$
(40,413
)
 
 
$
887,029

LIABILITIES AND STOCKHOLDERS’ EQUITY
 

 
 
 
 


Current liabilities:
 

 
 
 
 


Accounts payable and accrued expenses
$
50,242

 
$
(1,755
)
(b)
 
$
48,487

Oil and gas revenue distribution payable
20,355

 
(3,321
)
(b)
 
17,034

Derivative liability
28,416

 
—

 
 
28,416

Total current liabilities
99,013

 
(5,076
)
 
 
93,937

 
 
 
 
 
 


Long-term liabilities:
 

 
 
 
 


Credit facility
60,000

 
(60,000
)
(c)
 
—

Ad valorem taxes
19,803

 
(466
)
(b)
 
19,337

Long-term derivative liability
4,657

 
—

 
 
4,657

Asset retirement obligations for oil and gas properties
28,154

 
—

 
 
28,154

Asset retirement obligations for oil and gas properties held for sale
5,386

 
(5,386
)
(b)
 
—

Total liabilities
217,013

 
(70,928
)
 
 
146,085

 
 
 
 
 
 


Commitments and contingencies
 
 
 
 
 


 
 
 
 
 
 


Stockholders’ equity:
 

 
 
 
 


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

 
—

 
 
—

Common stock, $.01 par value, 225,000,000 shares authorized, 20,534,799 issued and outstanding in 2018
4,286

 
—

 
 
4,286

Additional paid-in capital
692,434

 
—

 
 
692,434

Retained earnings
13,709

 
30,515

(d)
 
44,224

Total stockholders’ equity
710,429

 
30,515

 
 
740,944

Total liabilities and stockholders’ equity
$
927,442

 
$
(40,413
)
 
 
$
887,029

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

40
Table of Contents


BONANZA CREEK ENERGY, INC. AND SUBSIDIARIES
PRO FORMA CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME (LOSS) (UNAUDITED)
(in thousands, except share amounts)
 
Historical
 
 
 
 
Unaudited Pro Forma Statement of Operations
 
Three Months Ended June 30, 2018
 
Pro Forma Adjustments
 
 
Three Months Ended June 30, 2018
Operating net revenues:
 

 
 
 
 
 

Oil and gas sales
$
71,872

 
$
(12,434
)
(e)
 
$
59,438

Operating expenses:
 

 
 
 
 
 
Lease operating expense
11,316

 
(3,070
)
(f)
 
8,246

Gas plant and midstream operating expense
3,247

 
(1,066
)
(f)
 
2,181

Gathering, transportation and processing
1,660

 
—

 
 
1,660

Severance and ad valorem taxes
6,071

 
(732
)
(f)
 
5,339

Exploration
221

 
—

 
 
221

Depreciation, depletion and amortization
9,564

 
(230
)
(f)
 
9,334

Abandonment and impairment of unproved properties
2,477

 
—

 
 
2,477

Unused commitments
—

 
—

 
 
—

General and administrative
9,917

 
—

 
 
9,917

Total operating expenses
44,473

 
(5,098
)
 
 
39,375

Income (loss) from operations
27,399

 
(7,336
)
 
 
20,063

Other income (expense):
 

 
 
 
 
 
Derivative loss
(22,012
)
 
—

 
 
(22,012
)
Interest expense
(805
)
 
—

 
 
(805
)
Reorganization items, net
—

 
—

(j)
 
—

Other income
277

 
—

 
 
277

Total other (expense)
(22,540
)
 
—

 
 
(22,540
)
Income (loss) from operations before taxes
4,859

 
(7,336
)
 
 
(2,477
)
Income tax benefit (expense)
—

 
—

 
 
—

Net income (loss)
$
4,859

 
$
(7,336
)
 
 
$
(2,477
)
 
 
 
 
 
 
 
Comprehensive income (loss)
$
4,859

 
$
(7,336
)
 
 
$
(2,477
)
 
 
 
 
 
 
 
Basic net income (loss) per common share
$
0.24

 
 
 
 
$
(0.12
)
 
 
 
 
 
 
 
Diluted net income (loss) per common share
$
0.24

 
 
 
 
$
(0.12
)
 
 
 
 
 
 
 
Basic weighted-average common shares outstanding
20,488

 
 
 
 
20,488

 
 
 
 
 
 
 
Diluted weighted-average common shares outstanding
20,603

 
 
 
 
20,488


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

41
Table of Contents

BONANZA CREEK ENERGY, INC. AND SUBSIDIARIES
PRO FORMA CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME (LOSS) (UNAUDITED)
(in thousands, except share amounts)
 
Historical
 
 
 
 
Unaudited Pro Forma Statement of Operations
 
Six Months Ended June 30, 2018
 
Pro Forma Adjustments
 
 
Six Months Ended June 30, 2018
Operating net revenues:
 

 
 
 
 
 

Oil and gas sales
$
136,064

 
$
(24,543
)
(e)
 
$
111,521

Operating expenses:
 

 
 
 
 


Lease operating expense
21,775

 
(6,105
)
(f)
 
15,670

Gas plant and midstream operating expense
6,860

 
(2,311
)
(f)
 
4,549

Gathering, transportation and processing
3,998

 
—

 
 
3,998

Severance and ad valorem taxes
11,303

 
(1,447
)
(f)
 
9,856

Exploration
250

 
—

 
 
250

Depreciation, depletion and amortization
17,072

 
(230
)
(f)
 
16,842

Abandonment and impairment of unproved properties
4,979

 
—

 
 
4,979

Unused commitments
21

 
—

 
 
21

General and administrative
19,451

 
—

 
 
19,451

Total operating expenses
85,709

 
(10,093
)
 
 
75,616

Income (loss) from operations
50,355

 
(14,450
)
 
 
35,905

Other income (expense):
 

 
 
 
 


Derivative loss
(30,754
)
 
—

 
 
(30,754
)
Interest expense
(1,162
)
 
—


 
(1,162
)
Reorganization items, net
—

 
—

(j)
 
—

Other income
290

 
21

(h)
 
311

Total other income (expense)
(31,626
)
 
21

 
 
(31,605
)
Income (loss) from operations before taxes
18,729

 
(14,429
)
 
 
4,300

Income tax benefit (expense)
—

 
—

 
 
—

Net income (loss)
$
18,729

 
$
(14,429
)
 
 
$
4,300

 
 
 
 
 
 


Comprehensive income (loss)
$
18,729

 
$
(14,429
)
 
 
$
4,300

 
 
 
 
 
 
 
Basic net income (loss) per common share
$
0.91

 
 
 
 
$
0.21

 
 
 
 
 
 
 
Diluted net income (loss) per common share
$
0.91

 
 
 
 
$
0.21

 
 
 
 
 
 
 
Basic weighted-average common shares outstanding
20,471

 
 
 
 
20,471

 
 
 
 
 
 
 
Diluted weighted-average common shares outstanding
20,538

 
 
 
 
20,538


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







42
Table of Contents

BONANZA CREEK ENERGY, INC. AND SUBSIDIARIES
PRO FORMA CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME (LOSS) (UNAUDITED)
(in thousands, except share amounts)
 
Historical
 
 
 
 
 
 
Predecessor
 
Successor
 
 
 
 
Unaudited Pro Forma Combined Statement of Operations
December 31, 2017
 
January 1, 2017 through April 28, 2017
 
April 29, 2017 through December 31, 2017
 
Pro Forma Adjustments
 
 
Operating net revenues:
 
 
 

 
 
 
 
 

Oil and gas sales
$
68,589

 
$
123,535

 
$
(43,725
)
(e)
 
$
148,399

Operating expenses:
 

 
 

 
 
 
 


Lease operating expense
13,128

 
25,862

 
(11,898
)
(f)
 
27,092

Gas plant and midstream operating expense
3,541

 
8,341

 
(5,964
)
(f)
 
5,918

Gathering, transportation and processing
—

 
—

 
—

 
 
—

Severance and ad valorem taxes
5,671

 
9,590

 
(2,351
)
(f)
 
12,910

Exploration
3,699

 
3,745

 
(628
)
(f)
 
6,816

Depreciation, depletion and amortization
28,065

 
21,312

 
(5,099
)
(f)
 
44,278

Abandonment and impairment of unproved properties
—

 
—

 
—

 
 
—

Unused commitments
993

 
—

 
—

 
 
993

General and administrative
15,092

 
42,676

 
—

 
 
57,768

Total operating expenses
70,189

 
111,526

 
(25,940
)
 
 
155,775

Income (loss) from operations
(1,600
)
 
12,009

 
(17,785
)
 
 
(7,376
)
Other income (expense):
 

 
 

 
 
 
 


Derivative loss
—

 
(15,365
)
 
—

 
 
(15,365
)
Interest expense
(5,656
)
 
(773
)
 
2,456

(g)
 
(3,973
)
Reorganization items, net
8,808

 
—

 
—

(j)
 
8,808

Other income
1,108

 
(1,267
)
 
506

(i)
 
347

Total other income (expense)
4,260

 
(17,405
)
 
2,962

 
 
(10,183
)
Income (loss) from operations before taxes
2,660

 
(5,396
)
 
(14,823
)
 
 
(17,559
)
Income tax benefit (expense)
—

 
376

 
—

 
 
376

Net income (loss)
$
2,660

 
$
(5,020
)
 
$
(14,823
)
 
 
$
(17,183
)
 
 
 
 
 
 
 
 


Comprehensive income (loss)
$
2,660

 
$
(5,020
)
 
$
(14,823
)
 
 
$
(17,183
)
 
 
 
 
 
 
 
 
 
Basic net income (loss) per common share
$
0.05

 
$
(0.25
)
 
 
 
 
$
(0.84
)
 
 
 
 
 
 
 
 
 
Diluted net income (loss) per common share
$
0.05

 
$
(0.25
)
 
 
 
 
$
(0.84
)
 
 
 
 
 
 
 
 
 
Basic weighted-average common shares outstanding
49,559

 
20,427

 
 
 
 
20,427

 
 
 
 
 
 
 
 
 
Diluted weighted-average common shares outstanding
50,971

 
20,427

 
 
 
 
20,427


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







43
Table of Contents

Notes to Unaudited Pro Forma Condensed Consolidated Financial Statements

(1) Basis of Presentation
The accompanying unaudited pro forma consolidated financial statements give effect to pro forma adjustments to reflect the sale of BCEOC as if the sale had occurred as of the beginning of the period presented in the pro forma statements of income for the three and six months ended June 30, 2018 and for the year ended December 31, 2017 and as if the sale had occurred on June 30, 2018 in the pro forma balance sheet.

(2) Pro Forma Adjustments
The unaudited pro forma condensed consolidated balance sheets and statements of operations and comprehensive income (loss) reflect the effect of the following pro forma adjustments:

(a) The increase in cash represents the difference between the net proceeds at closing of $102.9 million and the assumed paydown of the outstanding borrowings under the Company's credit facility of $60.0 million as of June 30, 2018.

(b) Portrays the sale of assets as if the sale had occurred on June 30, 2018.

(c) The paydown of the credit facility with a portion of the net cash proceeds from the divestiture. This $60.0 million represents the outstanding balance on the credit facility as of June 30, 2018.

(d) The effect on stockholder's equity as a result of adjustments (a) through (c).

(e) Elimination of oil, natural gas, and natural gas liquids related revenues directly from the Mid-Con Assets for the three and six months ended June 30, 2018 and for the year ended December 31, 2017.

(f) Elimination of direct operating expenses from the Mid-Con Assets for the three and six months ended June 30, 2018 and for the year ended December 31, 2017.

(g) The reversal of interest expense relating to the Company's predecessor credit facility in conjunction with the paydown of the credit facility with proceeds received from the divestiture for the year ended December 31, 2017. As discussed in Note 1, for pro forma statements of operations it is assumed that the transaction occurred at the beginning of the earliest period presented, therefore it is assumed the sale occurred on January 1, 2017 and the proceeds from the sale were applied to the predecessor credit facility balance as of January 1, 2017.

(h) Elimination of other expenses directly related to the Mid-Con Assets for the six months ended June 30, 2018. These expenses specifically relate to contract deficiency payments.

(i) Addback of other losses directly related to the Mid-Con Assets for the year ended December 31, 2017.

(j) Pursuant to the Securities and Exchange Commission’s requirement that infrequent or nonrecurring items included in the underlying historical financial statements that are not directly affected by the transaction be left intact instead of being eliminated, we did not adjust “Reorganization items, net” for the potential effects the Mid-Con Asset sale may have had on our fresh start valuations upon our emergence from bankruptcy, nor do we believe such adjustment to be meaningful.


44
Table of Contents

Item 6. Exhibits.
Exhibit
No.
    
Description of Exhibit
 
 
 
 
 
 
 
 

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
†                 Filed or furnished herewith


45
Table of Contents

SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
 
 
 
 
BONANZA CREEK ENERGY, INC.
 
 
 
 
Date:
August 8, 2018
    
By:
/s/ Eric T. Greager
 
 
 
 
Eric T. Greager
 
 
 
 
President and Chief Executive Officer
 
 
 
 
(principal executive officer)
 
 
 
 
 
 
 
 
 
 
 
 
 
By:
/s/ Scott A. Fenoglio
 
 
 
 
Scott A. Fenoglio
 
 
 
 
Senior Vice President, Finance & Planning
 
 
 
 
(principal financial officer)
 
 
 
 
 
 
 
 
 
 
 
 
 
By:
/s/ Sandi K. Garbiso
 
 
 
 
Sandi K. Garbiso
 
 
 
 
Vice President and Chief Accounting Officer
 
 
 
 
(principal accounting officer)


46