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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 September 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 November 5, 2018, the registrant had 20,543,940 shares of common stock outstanding.
 

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BONANZA CREEK ENERGY, INC.
INDEX
 
 
    
    
PAGE
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 


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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
 
September 30, 2018
 
December 31, 2017
ASSETS
 

 
 

Current assets:
 

 
 

Cash and cash equivalents
$
24,007

 
$
12,711

Accounts receivable:
 

 
 

Oil and gas sales
36,085

 
28,549

Joint interest and other
39,118

 
3,831

Prepaid expenses and other
5,365

 
6,555

Inventory of oilfield equipment
1,759

 
1,019

Derivative assets
134

 
488

Total current assets
106,468

 
53,153

Property and equipment (successful efforts method):
 

 
 

Proved properties
584,672

 
555,341

Less: accumulated depreciation, depletion and amortization
(39,644
)
 
(17,032
)
Total proved properties, net
545,028

 
538,309

Unproved properties
177,552

 
183,843

Wells in progress
102,462

 
47,224

Other property and equipment, net of accumulated depreciation of $2,382 in 2018 and $2,224 in 2017
3,766

 
4,706

Total property and equipment, net
828,808

 
774,082

Long-term derivative assets

 
6

Other noncurrent assets
3,159

 
3,130

Total assets
$
938,435

 
$
830,371

LIABILITIES AND STOCKHOLDERS’ EQUITY
 

 
 

Current liabilities:
 

 
 

Accounts payable and accrued expenses (note 5)
$
72,720

 
$
62,129

Oil and gas revenue distribution payable
16,119

 
15,667

Derivative liability
34,419

 
11,423

Total current liabilities
123,258

 
89,219

 
 
 
 
Long-term liabilities:
 

 
 

Credit facility

 

Ad valorem taxes
25,174

 
11,584

Long-term derivative liability
6,504

 
2,972

Asset retirement obligations for oil and gas properties
27,903

 
38,262

Total liabilities
182,839

 
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, 20,543,940 and 20,453,549 issued and outstanding in 2018 and 2017, respectively
4,286

 
4,286

Additional paid-in capital
694,238

 
689,068

Retained earnings (deficit)
57,072

 
(5,020
)
Total stockholders’ equity
755,596

 
688,334

Total liabilities and stockholders’ equity
$
938,435

 
$
830,371

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

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BONANZA CREEK ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME (UNAUDITED)
(in thousands, except per share amounts)
 
 
Successor
 
Three Months Ended
September 30, 2018
 
Three Months Ended September 30, 2017
Operating net revenues:
 

 
 
Oil and gas sales
$
74,380

 
$
45,232

Operating expenses:
 

 
 
Lease operating expense
7,951

 
9,643

Gas plant and midstream operating expense
2,249

 
3,265

Gathering, transportation, and processing
2,749

 

Severance and ad valorem taxes
6,485

 
2,434

Exploration
(6
)
 

Depreciation, depletion, and amortization
10,987

 
7,350

Abandonment and impairment of unproved properties
430

 

General and administrative (including $1,741 and $2,646, respectively, of stock-based compensation)
10,899

 
15,181

Total operating expenses
41,744

 
37,873

Income from operations
32,636

 
7,359

Other income (expense):
 

 
 
Derivative loss
(16,078
)
 
(2,762
)
Interest expense
(608
)
 
(265
)
Gain on sale of properties
26,720

 

Other income (expense)
693

 
(4
)
Total other income (expense)
10,727

 
(3,031
)
Income from operations before taxes
43,363

 
4,328

Income tax benefit (expense)

 

Net income
$
43,363

 
$
4,328

 
 
 
 
Comprehensive income
$
43,363

 
$
4,328

 
 
 
 
Basic net income per common share
$
2.11

 
$
0.21

 
 
 
 
Diluted net income per common share
$
2.10

 
$
0.21




 
 
Basic weighted-average common shares outstanding
20,541

 
20,439




 
 
Diluted weighted-average common shares outstanding
20,631

 
20,447

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




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

 
 
 
 
 

Oil and gas sales
$
210,444

 
$
73,346

 
 
$
68,589

Operating expenses:
 

 
 
 
 
 

Lease operating expense
29,726

 
15,796

 
 
13,128

Gas plant and midstream operating expense
9,109

 
5,027

 
 
3,541

Gathering, transportation, and processing
6,747

 

 
 

Severance and ad valorem taxes
17,788

 
4,842

 
 
5,671

Exploration
244

 
359

 
 
3,699

Depreciation, depletion, and amortization
28,059

 
12,186

 
 
28,065

Abandonment and impairment of unproved properties
5,409

 

 
 

Unused commitments
21

 

 
 
993

General and administrative (including $4,933, $10,595 and $2,116, respectively, of stock-based compensation)
30,350

 
31,320

 
 
15,092

Total operating expenses
127,453

 
69,530

 
 
70,189

Income (loss) from operations
82,991

 
3,816

 
 
(1,600
)
Other income (expense):
 

 
 
 
 
 

Derivative loss
(46,832
)
 
(2,762
)
 
 

Interest expense
(1,770
)
 
(460
)
 
 
(5,656
)
Gain on sale of properties
26,720

 

 
 

Reorganization items, net (note 2)

 

 
 
8,808

Other income
983

 
154

 
 
1,108

Total other income (expense)
(20,899
)
 
(3,068
)
 
 
4,260

Income from operations before taxes
62,092

 
748

 
 
2,660

Income tax benefit (expense)

 

 
 

Net income
$
62,092

 
$
748

 
 
$
2,660

 
 
 
 
 
 
 
Comprehensive income
$
62,092

 
$
748

 
 
$
2,660

 
 
 
 
 
 
 
Basic net income per common share
$
3.03

 
$
0.04

 
 
$
0.05

 
 
 
 
 
 
 
Diluted net income per common share
$
3.02

 
$
0.04

 
 
$
0.05

 
 
 
 
 
 
 
Basic weighted-average common shares outstanding
20,495

 
20,410

 
 
49,559

 
 
 
 
 
 
 
Diluted weighted-average common shares outstanding
20,587

 
20,438

 
 
50,971

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


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

 
$
4,286

 
$
689,068

 
$
(5,020
)
 
$
688,334

Restricted common stock issued
 
84,345

 
 

 
 

 
 

 
 

Restricted stock used for tax withholdings
 
(25,991
)
 
 

 
 
(863
)
 
 

 
 
(863
)
Exercise of stock options
 
32,037

 
 

 
 
1,100

 
 

 
 
1,100

Stock-based compensation
 

 
 

 
 
4,933

 
 

 
 
4,933

Net income
 

 
 

 
 

 
 
62,092

 
 
62,092

Balances, September 30, 2018
 
20,543,940

 
$
4,286

 
$
694,238

 
$
57,072

 
$
755,596

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



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

 
 
 
 
 

Net income
$
62,092

 
$
748

 
 
$
2,660

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

Depreciation, depletion, and amortization
28,059

 
12,186

 
 
28,065

Non-cash reorganization items

 

 
 
(44,160
)
Abandonment and impairment of unproved properties
5,409

 

 
 

Well abandonment costs and dry hole expense

 
74

 
 
2,931

Stock-based compensation
4,933

 
10,595

 
 
2,116

Amortization of deferred financing costs and debt premium

 

 
 
374

Derivative loss
46,832

 
2,762

 
 

Derivative cash settlements
(19,944
)
 

 
 

Gain on sale of oil and gas properties
(26,720
)
 

 
 

Other

 
7

 
 
18

Changes in current assets and liabilities:
 
 
 
 
 
 

Accounts receivable
(42,823
)
 
(2,027
)
 
 
(6,640
)
Prepaid expenses and other assets
983

 
(80
)
 
 
963

Accounts payable and accrued liabilities
9,698

 
(11,910
)
 
 
(5,880
)
Settlement of asset retirement obligations
(1,497
)
 
(936
)
 
 
(331
)
Net cash provided by (used in) operating activities
67,022

 
11,419

 
 
(19,884
)
Cash flows from investing activities:
 

 
 
 
 
 

Acquisition of oil and gas properties
(1,929
)
 
(5,074
)
 
 
(445
)
Exploration and development of oil and gas properties
(156,820
)
 
(42,355
)
 
 
(5,123
)
Proceeds from sale of oil and gas properties
103,134

 

 
 

Additions to property and equipment - non oil and gas
(340
)
 
(667
)
 
 
(454
)
Net cash used in investing activities
(55,955
)
 
(48,096
)
 
 
(6,022
)
Cash flows from financing activities:
 

 
 
 
 
 

Proceeds from credit facility
60,000

 

 
 

Payments to credit facility
(60,000
)
 

 
 
(191,667
)
Proceeds from sale of common stock

 

 
 
207,500

Proceeds from exercise of stock options
1,100

 

 
 

Payment of employee tax withholdings in exchange for the return of common stock
(863
)
 
(2,398
)
 
 
(427
)
Net cash provided by (used in) financing activities
237

 
(2,398
)
 
 
15,406

Net change in cash, cash equivalents and restricted cash
11,304

 
(39,075
)
 
 
(10,500
)
Cash, cash equivalents and restricted cash:
 

 
 
 
 
 

Beginning of period
12,782

 
70,246

 
 
80,746

End of period
$
24,086

 
$
31,171

 
 
$
70,246

Supplemental cash flow disclosure:
 

 
 
 
 
 

Cash paid for interest
$
2,020

 
$
455

 
 
$
3,509

Cash paid for reorganization items
$

 
$
918

 
 
$
52,968

Changes in working capital related to drilling expenditures
$
17,461

 
$
9,325

 
 
$
3,360

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

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

NOTE 1 - ORGANIZATION AND BUSINESS
Bonanza Creek Energy, Inc. (“BCEI” or, together with our consolidated subsidiaries, the “Company”) is engaged primarily in acquiring, developing, exploiting and producing oil and gas properties. The Company's assets and operations are concentrated in the Wattenberg Field in Colorado.
NOTE 2 - BASIS OF PRESENTATION
These unaudited condensed consolidated financial statements have been prepared in accordance with U.S. generally accepted accounting principles (“GAAP”) for interim financial statements and pursuant to the rules and regulations of the Securities and Exchange Commission. In the opinion of management, the accompanying unaudited condensed consolidated financial statements reflect all adjustments consisting of normal recurring adjustments as necessary for a fair presentation of our financial position and results of operations. Interim results of operations are not necessarily indicative of the results to be expected for the full fiscal year. As described below, however, prior financial statements are not comparable to our interim financial statements due to the adoption of fresh-start accounting.
The financial information as of December 31, 2017, has been derived from the audited financial statements contained in our Annual Report on Form 10-K for the year ended December 31, 2017 (“2017 Form 10-K”), but does not include all disclosures, including notes required by GAAP. As such, this quarterly report should be read in conjunction with the consolidated financial statements and related notes included in our 2017 Form 10-K. The Company follows the same accounting principles for preparing quarterly and annual reports.
On January 4, 2017, the Company and certain of its subsidiaries (collectively with the Company, the “Debtors”) filed voluntary petitions (the “Bankruptcy Petitions,” and the cases commenced thereby, the “Chapter 11 Cases”) under Chapter 11 of the United States Bankruptcy Code (the “Bankruptcy Code”) in the United States Bankruptcy Court for the District of Delaware (the “Bankruptcy Court”) to pursue the Debtors’ Joint Prepackaged Plan of Reorganization Under Chapter 11 of the Bankruptcy Code (as proposed, the “Plan”). The Bankruptcy Court granted the Debtors' motion seeking to administer all of the Debtors' Chapter 11 Cases jointly under the caption In re Bonanza Creek Energy, Inc., et al (Case No. 17-10015). The Debtors received bankruptcy court confirmation of their Plan on April 7, 2017, and emerged from bankruptcy on April 28, 2017 (the “Effective Date”).
Upon emergence from bankruptcy, the Company adopted fresh-start accounting and became a new entity for financial reporting purposes. As a result of the application of fresh-start accounting and the effects of the implementation of the Plan, the Company’s condensed consolidated financial statements after April 28, 2017 are not comparable with the financial statements on or prior to April 28, 2017. The Company's condensed consolidated financial statements and related footnotes are presented with a black line division which delineates the lack of comparability between amounts presented after April 28, 2017 and dates prior thereto.
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 nine months ended September 30, 2018, respectively. References to “Prior Successor Quarter” relate to the three months ended September 30, 2017 and “Prior Successor Period” relate to the period of April 29, 2017 through September 30, 2017. References to “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 the Financial Accounting Standards Board (“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.

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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 (“accompanying statements of operations”). The following table summarizes reorganization items (in thousands):
Gain on settlement of liabilities subject to compromise
$
412,852

Payment on predecessor credit facility fees and remaining unaccrued 2016 STIP
(1,007
)
Fresh-start valuation adjustments
(311,361
)
Legal and professional fees and expenses
(34,335
)
Write-off of debt issuance and premium costs
(6,156
)
Make-whole payment on Senior Notes
(51,185
)
Total reorganization items, net
$
8,808

Principles of Consolidation
     As of September 30, 2018, the balance sheets include the accounts of the Company and its wholly owned subsidiaries, Bonanza Creek Energy Operating Company, LLC, Holmes Eastern Company, LLC and Rocky Mountain Infrastructure, LLC. All significant intercompany accounts and transactions have been eliminated.
On August 6, 2018, the Company sold its equity interests in Bonanza Creek Energy Resources, LLC, which in turn owns all of the outstanding equity interest in Bonanza Creek Energy Upstream LLC and Bonanza Creek Energy Midstream, LLC. These subsidiaries comprise the Company's Mid-Continent region and assets. Please refer to Note 4 - Divestitures for additional discussion.
As of December 31, 2017, 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.
Reclassifications
    
Certain prior period balances have been reclassified to conform to current period presentation. Such reclassifications did not impact total revenues, operating income, net income, cash provided by (used in) operating activities, cash used in investing activities, cash provided by (used in) financing activities, or the consolidated statement of stockholders’ equity.
 
For the nine months ended September 30, 2018, the accompanying condensed consolidated statements of cash flows (“accompanying statements of cash flows”) includes a reclassification of $0.2 million within cash flows from operating activities, from other to gain on sale of oil and gas properties.
 
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 FASB issued Update No. 2014-09, Revenue from Contracts with Customers (Topic 606) (“ASC 606”). 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

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sheet. The standard is effective for annual reporting periods beginning after December 15, 2017, and interim periods within those annual periods. We adopted the new standard on January 1, 2018 and its adoption did not have a significant impact on our financial statements. Please refer to Note 3 - Revenue Recognition for additional discussion.
In January 2016, the FASB issued Update No. 2016-01 - Financial Instruments - Overall to require separate presentation of financial assets and financial liabilities by measurement category and form of financial asset on the balance sheet or the accompanying notes to the financial statements. This authoritative guidance is effective for fiscal years beginning after December 15, 2017 and interim periods within those fiscal years. We adopted the new standard on January 1, 2018 and its adoption did not have a material impact on our financial statements and disclosures.
In August 2016, the FASB issued Update No. 2016-15 - Classification of Certain Cash Receipts and Cash Payments, which clarifies the presentation of specific cash receipts and cash payments within the statement of cash flows. This authoritative accounting guidance is effective for annual periods, and interim periods within those annual periods, beginning after December 15, 2017. Early adoption is permitted. We adopted the new standard on January 1, 2018 and its adoption did not have a material impact on our statements of cash flows and related disclosures.
In November 2016, the FASB issued Update No. 2016-18, Statement of Cash Flows (Topic 230): Restricted Cash. This update clarifies how entities should present restricted cash and restricted cash equivalents in the statement of cash flows by including them with cash and cash equivalents when reconciling the total beginning and ending amounts for the periods shown on the statement of cash flows. This guidance is to be applied using a retrospective method and is effective for annual periods, and interim periods within those annual periods, beginning after December 15, 2017. Early adoption is permitted. We adopted the new standard on January 1, 2018 and the prior period has been adjusted to conform to the current period presentation, which resulted in an increase in cash used in investing activities of $0.1 million for the 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 statements of cash flows (in thousands):
 
Successor
 
As of September 30, 2018
 
As of December 31, 2017
 
As of September 30, 2017
Cash and cash equivalents
$
24,007

 
$
12,711

 
$
31,096

Restricted cash included in other noncurrent assets
79

 
71

 
75

Total cash, cash equivalents and restricted cash as shown in the statements of cash flows
$
24,086

 
$
12,782

 
$
31,171

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 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.

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Recently Issued Accounting Standards
In February 2016, the FASB issued Update No. 2016-02 – Leases (Topic 842) 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 Leases (Topic 842): Targeted Improvements, which provides for an additional transition method that allows an entity to initially apply the new leases standard at the adoption date and recognize a cumulative-effect adjustment to the opening balance of retained earnings (deficit) in the period of adoption. For example, comparative periods presented in the financial statements will continue to be in accordance with current guidance, 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 reviewing all contracts, making initial assessments, acquiring lease accounting software, and putting processes and internal controls in place to accommodate adoption of this guidance.
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 September 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 September 30, 2018
 
As Unadjusted(1)
 
ASC 606 Adjustments
 
As Reported
Operating Revenues:
 
 
 
 
 
    Oil sales
$
62,142

 
$

 
$
62,142

    Natural gas sales
 
3,947

 
 
1,246

 
 
5,193

    NGLs sales
 
5,542

 
 
1,503

 
 
7,045

Oil and gas sales
$
71,631

 
$
2,749

 
$
74,380

 
 
 
 
 
 
 
 
 
Operating expenses:
 
 
 
 
 
 
 
 
    Gathering, transportation and processing
$

 
$
2,749

 
$
2,749

 
 
 
 
 
 
 
 
 
Net income
$
43,363

 
$

 
$
43,363


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Nine Months Ended September 30, 2018
 
As Unadjusted(1)
 
ASC 606 Adjustments
 
As Reported
Operating Revenues:
 
 
 
 
 
    Oil sales
$
174,856

 
$

 
$
174,856

    Natural gas sales
 
13,309

 
 
3,043

 
 
16,352

    NGLs sales
 
15,532

 
 
3,704

 
 
19,236

Oil and gas sales
$
203,697

 
$
6,747

 
$
210,444

 
 
 
 
 
 
 
 
 
Operating expenses:
 
 
 
 
 
 
 
 
    Gathering, transportation and processing
$

 
$
6,747

 
$
6,747

 
 
 
 
 
 
 
 
 
Net income
$
62,092

 
$

 
$
62,092

____________________
(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.


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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 September 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 September 30, 2018 and December 31, 2017, our receivables from contracts with customers were $36.1 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 September 30, 2018, revenue recognized in the reporting period related to performance obligations satisfied in prior reporting periods was not material.
NOTE 4 - DIVESTITURES
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.
On August 6, 2018, the Company entered into an agreement to simultaneously close and divest of all of its assets within its Mid-Continent region. Net proceeds from the sale amounted to $102.9 million, subject to customary post-closing adjustments, resulted in a gain of approximately $26.7 million, included in the gain on sale of properties line item in the accompanying statements of operations. The original purchase price of $117.0 million was subject to customary purchase-price adjustments, comprised of operational cash activity related to the Mid-Continent assets, for the time period between the effective date of February 1, 2018 and the closing date of August 6, 2018. The divestiture did not represent a strategic shift and is not expected to have a significant effect on the Company's operations or financial results; therefore, the disposal did not meet the criteria of discontinued operations.

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NOTE 5 - ACCOUNTS PAYABLE AND ACCRUED EXPENSES
Accounts payable and accrued expenses contain the following (in thousands):
 
Successor
 
As of September 30, 2018
 
As of December 31, 2017
Accrued drilling and completion costs
$
39,294

 
$
21,833

Accounts payable trade
16,624

 
6,256

Accrued general and administrative cost
4,312

 
10,025

Accrued lease operating expense
2,407

 
5,005

Accrued interest

 
250

Accrued oil and gas hedging
2,827

 
808

Accrued production and ad valorem taxes and other
7,256

 
17,952

Total accounts payable and accrued expenses
$
72,720

 
$
62,129

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

 
$

Total long-term debt
$

 
$

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 were adjusted to provide the Company with greater flexibility to participate in asset swaps. The next redetermination of our credit facility borrowing base is expected to occur before year-end. The Company had nothing outstanding under its credit facility as of September 30, 2018 and $30.0 million as of the date of filing.
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 September 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.

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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 its 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 $1.6 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 gross 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 gross volume commitment will be approximately 10,100 barrels per day, and the minimum gross 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 gross barrels per day. The aggregate financial commitment fee over the remaining term, based on the minimum gross volume commitment schedule (as defined in the agreement) and the applicable differential fee, is $141.9 million as of September 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.

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The annual minimum commitment payments under the NGL agreement and the office lease for the next five years as of September 30, 2018 are presented below (in thousands):
 
    
NGL Gross Commitments(1)
 
Office Lease Commitments
 
Total
2018
 
$
3,025

$

$
3,025

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
 
$
141,874

$
4,222

$
146,096

_______________________________
(1) The above calculation is based on the minimum gross volume commitment schedule (as defined in the NGL agreement) and applicable differential fees.
There have been no other material changes from the commitments disclosed in the notes to the Company’s consolidated financial statements included in our 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 354,450 RSUs with a fair value of $9.9 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 Quarter and Period was $1.3 million and $3.7 million, respectively. As of September 30, 2018, unrecognized compensation cost was $11.3 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
354,450

 
$
27.81

Vested
(84,345
)
 
$
30.63

Forfeited
(66,353
)
 
$
29.79

Non-vested at end of quarter
464,917

 
$
30.34

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

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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 Period, the Company granted 59,641 PSUs to certain officers with a fair value of $1.8 million. For the Current Successor Quarter and Period, the Company recognized compensation expense of $0.1 million and $0.2 million, respectively. As of September 30, 2018, unrecognized compensation cost was $1.5 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 Period:
 
 
For the Nine Months Ended September 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 Period. Total expense recorded for stock options for the Current Successor Quarter and Period was $0.3 million and $1.0 million, respectively. As of September 30, 2018, unrecognized compensation cost was $1.2 million and will be amortized through 2020.

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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
(32,037
)
 
34.36

 

 
$

Forfeited
(22,901
)
 
34.36

 

 
$

Outstanding at end of quarter
142,333

 
$
34.36

 
8.1

 
$

A summary of additional information related to options outstanding and exercisable as of September 30, 2018 is presented below:
Exercise Price
Number of Options Outstanding and Exercisable
Weighted-Average Remaining Contractual Life (in years)
$34.36
52,003
7.4
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 September 30, 2018 and December 31, 2017 and their classification within the fair value hierarchy (in thousands):
 
As of September 30, 2018
 
Level 1
 
Level 2
 
Level 3
Derivative assets(1)
$

 
$
134

 
$

Derivative liabilities(1)
$

 
$
40,923

 
$

Unproved properties(2)
$

 
$

 
$
177,552


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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 $183.0 million, to their fair value of $177.6 million, and recognized an impairment of unproved properties for the Current Successor Period of $5.4 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 September 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 Company had no outstanding balance under the credit facility as of December 31, 2017 and September 30, 2018.
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%.     

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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
 
(1,084
)
Additions
 
279

Accretion expense
 
1,370

Sold properties
 
(10,924
)
Ending balance as of September 30, 2018
$
27,903


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. In the event that the settlement price is between the ceiling and the floor, no payment or receipt occurs.
A basis swap arrangement guarantees a price differential from a specified delivery point. The Company receives the difference between the price differential and the stated terms, if the price differential is greater than the stated terms. The Company pays the difference between the price differential and the stated terms, if the stated terms are greater than the price differential.

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As of September 30, 2018, the Company had entered into the following commodity derivative contracts:
 
 
Crude Oil
(NYMEX WTI)
 
Natural Gas
(NYMEX Henry Hub)
 
Natural Gas
(CIG Basis)
 
 
Bbls/day
 
Weighted Avg. Price per Bbl
 
MMBtu/day
 
Weighted Avg. Price per MMBtu
 
MMBtu/day
 
Weighted Avg. Basis Differential to CIG Price per MMBtu
4Q18
 
 
 
 
 
 
 
 
 
 
 
 
Cashless Collar
 
2,000

 
$43.00/$53.50
 
12,600

 
$2.75/$3.35
 

 

Swap
 
5,000

 
$58.07
 

 
 

 

Basis Swap
 

 
 

 
 
12,600

 
$0.67
1Q19
 
 
 
 
 
 
 
 
 
 
 
 
Cashless Collar
 
3,500

 
$50.29/$62.23
 
7,600

 
$2.75/$3.22
 

 

Swap
 
5,000

 
$59.33
 

 
 

 

Basis Swap
 

 
 

 
 
7,600

 
$0.665
2Q19
 
 
 
 
 
 
 
 
 
 
 
 
Cashless Collar
 
4,830

 
$54.35/$66.80
 
2,505

 
$2.75/$3.22
 

 

Swap
 
4,500

 
$58.32
 

 
 

 

3Q19
 
 
 
 
 
 
 
 
 
 
 
 
Cashless Collar
 
1,500

 
$60.00/$72.50
 

 
 

 

Swap
 
6,000

 
$59.94
 

 
 

 

4Q19
 
 
 
 
 
 
 
 
 
 
 
 
Cashless Collar
 
1,500

 
$60.00/$72.50
 

 
 

 

Swap
 
6,000

 
$59.94
 

 
 

 

1Q20
 
 
 
 
 
 
 
 
 
 
 
 
Swap
 
3,000

 
$63.48
 

 
 

 


21

Table of Contents

As of the filing date of this report, the Company had entered into the following commodity derivative contracts:
 
 
Crude Oil
(NYMEX WTI)
 
Natural Gas
(NYMEX Henry Hub)
 
Natural Gas
(CIG Basis)
 
Natural Gas
(CIG)
 
 
Bbls/day
 
Weighted Avg. Price per Bbl
 
MMBtu/day
 
Weighted Avg. Price per MMBtu
 
MMBtu/day
 
Weighted Avg. Basis Differential to CIG Price per MMBtu
 
MMBtu/day
 
Weighted Avg. Price per MMBtu
4Q18
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Cashless Collar
 
2,000

 
$43.00/$53.50
 
12,600

 
$2.75/$3.35
 

 

 

 

Swap
 
5,000

 
$58.07
 

 
 

 

 

 

Basis Swap
 

 
 

 
 
12,600

 
0.67

 

 

1Q19
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Cashless Collar
 
3,500

 
$50.29/$62.23
 
7,600

 
$2.75/$3.22
 

 

 

 

Swap
 
5,000

 
$59.33
 
1,500

 
3.13
 
7,600

 
$
0.67

 
10,000

 
2.17

2Q19
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Cashless Collar
 
4,830

 
$54.35/$66.80
 
2,505

 
$2.75/$3.22
 

 

 

 

Swap
 
4,500

 
$58.32
 

 
 

 
$

 
10,000

 
2.17

3Q19
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Cashless Collar
 
2,500

 
$60.00/$75.86
 

 
 

 

 

 

Swap
 
6,000

 
$59.94
 

 
 

 
$

 
10,000

 
2.17

4Q19
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Cashless Collar
 
2,500

 
$60.00/$75.86
 

 
 

 

 

 

Swap
 
6,000

 
$59.94
 

 
 

 
$

 
10,000

 
2.17

1Q20
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Swap
 
3,000

 
$63.48
 

 
 

 

 

 

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 September 30, 2018 and December 31, 2017 (in thousands):
 
 
 
Successor
 
 
 
As of September 30, 2018
 
As of December 31, 2017
 
Balance Sheet Location
 
Fair Value
 
Fair Value
Derivative Assets:
 
 
 
 
 

Commodity contracts
Current assets
 
$
134

 
$
488

Commodity contracts
Noncurrent assets
 

 
6

Derivative Liabilities:
 
 
 

 
 

Commodity contracts
Current liabilities
 
(34,419
)
 
(11,423
)
Commodity contracts
Long-term liabilities
 
(6,504
)
 
(2,972
)
Total derivative liabilities, net
 
 
$
(40,789
)
 
$
(13,901
)

22

Table of Contents

The Company had not entered into any derivative contracts as of September 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 September 30, 2018
 
Nine Months Ended September 30, 2018
Derivative cash settlement gain (loss):
 
 
 

Oil contracts
$
(8,292
)
 
$
(20,117
)
Gas contracts
$
(30
)
 
173

Total derivative cash settlement loss(1)
$
(8,322
)
 
$
(19,944
)
 
 
 
 
Change in fair value liability
(7,756
)
 
$
(26,888
)
 
 
 
 
Total derivative loss(1)
$
(16,078
)
 
$
(46,832
)
_______________________________
(1)
Total derivative loss and total derivative cash settlement loss for the Current Successor Quarter are reported in the derivative loss line item and derivative cash settlements line item in the accompanying statements of cash flows, within cash flows from operating activities. 
NOTE 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 issues PSUs, which represent the right to receive, upon settlement of the PSUs, a number of shares of the Company's common stock that range from zero to two times the number of PSUs granted on the award date. The number of potentially dilutive shares related to PSUs is based on the number of shares, if any, that would be issuable at the end of the respective reporting period, assuming that date was the end of the performance period applicable to such PSUs. The Company issued stock options and warrants, which both represent the right to purchase the Company's common stock at a specified price. The number of potentially dilutive shares related to the stock options is based on the number of shares, if any, that would be exercised at the end of the respective reporting period, assuming that date was the end of such stock options' term. The number of potentially dilutive shares related to the warrants is based on the number of shares, if any, that would be exercisable at the end of the respective reporting period.
Please refer to Note 8 - Stock-Based Compensation for additional discussion.

23

Table of Contents

The RSUs, PSUs, stock options, and warrants of the Company are all non-participating securities, and therefore, the Company uses the treasury stock method to calculate earnings per share as shown in the following table (in thousands, except per share amounts):
 
Successor
 
Three Months Ended September 30, 2018
 
Nine Months Ended September 30, 2018
 
Three Months Ended September 30, 2017
 
April 29, 2017 through September 30, 2017
Net income
$
43,363

 
$
62,092

 
$
4,328

 
$
748

 
 
 
 
 
 
 
 
Basic net income per common share
$
2.11

 
$
3.03

 
$
0.21

 
$
0.04

 
 
 
 
 
 
 
 
Diluted net income per common share
$
2.10

 
$
3.02

 
$
0.21

 
$
0.04

 
 
 
 
 
 
 
 
Weighted-average shares outstanding - basic
20,541

 
20,495

 
20,439

 
20,410

Add: dilutive effect of contingent stock awards
90

 
92

 
8

 
28

Weighted-average shares outstanding - diluted
20,631

 
20,587

 
20,447

 
20,438

There were 149,881 and 176,332 shares which were anti-dilutive for the Current Successor Quarter and Period, respectively. There were 628,872 and 628,897 shares which were anti-dilutive for the Prior Successor Quarter and Period, respectively.
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 PSUs, which represented the right to receive, upon settlement of the PSUs, a number of shares of the Predecessor Company’s common stock that ranged 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
 
January 1, 2017 through April 28, 2017
Net income
$
2,660

Less: undistributed income to unvested restricted stock
120

Undistributed income to common shareholders
2,540

Basic net income per common share
$
0.05

Diluted net income per common share
$
0.05

 
 
Weighted-average shares outstanding - basic
49,559

Add: dilutive effect of contingent stock awards
1,412

Weighted-average shares outstanding - diluted
50,971

There were 258,126 anti-dilutive shares in the Prior Predecessor Period.

24

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 September 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.

25

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 and operations are concentrated in the rural portions of the Wattenberg Field in Colorado.
As with many other jurisdictions, there is political risk to operating in Colorado. We believe the rural nature of our acreage within the Wattenberg Field, our existing gathering and processing facilities with multiple interconnects to third-party purchasers, and our flexible balance sheet provide us the opportunities to mitigate some of this risk.
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.
Financial and Operating Results
Our financial and operational results include:
Sales volumes of 17.7 MBoe per day for the third quarter of 2018 compared to 15.8 MBoe per day for the comparable period;
Lease operating expense per Boe for the third quarter of 2018 was $4.87 compared to $6.63 for the comparable period;
Total liquidity of $215.7 million at September 30, 2018, consisting of cash on hand plus funds available under our credit facility. Please refer to Liquidity and Capital Resources below for additional discussion;
Cash flows provided by operating activities for the nine months ended September 30, 2018 was $67.0 million, as compared to cash flows used in operating activities of $8.5 million during the combined Prior Successor and Predecessor Periods. Please refer to Liquidity and Capital Resources below for additional discussion; and
Net income for the nine months ended September 30, 2018 was $62.1 million as compared to net income of $3.4 million for the combined Prior Successor and Predecessor Periods.

26

Table of Contents

Outlook for 2018
The Company has accelerated 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 fourth quarter 2018 program is projected to grow Wattenberg production by approximately 50% when compared to the same period in 2017. The Company's annualized production is projected to grow by more than 50% in 2019. Allocated capital associated with the 2018 program is expected to be approximately $275.0 million to $295.0 million, which will support drilling approximately 80 gross wells and turning online 49 gross wells in 2018.


    

27

Table of Contents

Results of Operations
The results of operations are inclusive of the August 6, 2018 Mid-Continent asset sale.
The following table summarizes our revenues, sales volumes, and average sales prices for the periods indicated:
 
 
Successor
 
Three Months Ended September 30, 2018
 
Three Months Ended September 30, 2017
 
 
Change
 
Percent Change
Revenues:
 
 

 
 
 

 
 
 
 
 
Crude oil sales(1)
$
62,043

 
$
33,998

 
$
28,045

 
82
 %
Natural gas sales(2)
 
4,865

 
 
5,455

 
 
(590
)
 
(11
)%
Natural gas liquids sales (3)
 
7,045

 
 
5,410

 
 
1,635

 
30
 %
Product revenue
$
73,953

 
$
44,863

 
$
29,090

 
65
 %
 
 
 
 
 
 
 
 
 
 
 
Sales Volumes:
 
 
 
 
 
 
 
 
 
 
Crude oil (MBbls)(5)
 
977.0

 
 
760.2

 
 
216.8

 
29
 %
Natural gas (MMcf)(6)
 
2,193.4

 
 
2,340.6

 
 
(147.2
)
 
(6
)%
Natural gas liquids (MBbls)(7)
 
289.7

 
 
304.1

 
 
(14.4
)
 
(5
)%
Crude oil equivalent (MBoe)(3)
 
1,632.2

 
 
1,454.4

 
 
177.8

 
12
 %
 
 
 
 
 
 
 
 
 
 
 
Average Sales Prices (before derivatives)(4):
 
 

 
 
 

 
 
 
 
 
Crude oil (per Bbl)
$
63.50

 
$
44.72

 
$
18.78

 
42
 %
Natural gas (per Mcf)
$
2.22

 
$
2.33

 
$
(0.11
)
 
(5
)%
Natural gas liquids (per Bbl)
$
24.32

 
$
17.79

 
$
6.53

 
37
 %
Crude oil equivalent (per Boe)(3)
$
45.31

 
$
30.85

 
$
14.46

 
47
 %
 
 
 
 
 
 
 
 
 
 
 
Average Sales Prices (after derivatives)(4):
 
 
 
 
 
 
 
 
 
 
Crude oil (per Bbl)
$
55.02

 
$
44.72

 
$
10.30

 
23
 %
Natural gas (per Mcf)
$
2.20

 
$
2.33

 
$
(0.13
)
 
(6
)%
Natural gas liquids (per Bbl)
$
24.32

 
$
17.79

 
$
6.53

 
37
 %
Crude oil equivalent (per Boe)(3)
$
40.21

 
$
30.85

 
$
9.36

 
30
 %
_____________________________
(1)
Crude oil sales excludes $0.1 million of oil transportation revenues from third parties, which do not have associated sales volumes, for both the Current Successor Quarter and the Prior Successor Quarter.
(2)
Natural gas sales excludes $0.3 million of gas gathering revenues from third parties, which do not have associated sales volumes, for both the Current Successor Quarter and Prior Successor Quarter.
(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 Quarter, the derivative cash settlement loss for oil contracts was $8.3 million and the derivative cash settlement loss for natural gas contracts was immaterial. Please refer to Note 11 - Derivatives of Part I, Item 1 of this report for additional disclosures.
(5)
Crude oil sales volumes includes 44.5 MBbls and 167.1 MBbls of sales volumes from the Mid-Continent region for the Current Successor Quarter and the Prior Successor Quarter, respectively.
(6)
Natural gas sales volumes includes 194.5 MMcf and 550.4 MMcf of sales volumes from the Mid-Continent region for the Current Successor Quarter and the Prior Successor Quarter, respectively.
(7)
Natural gas liquids sales volumes includes 12.5 MBbls and 42.6 MBbls of sales volumes from the Mid-Continent region, for the Current Successor Quarter and the Prior Successor Quarter, respectively.
 
Revenues increased for the Current Successor Quarter by 65%, to $74.0 million, compared to $44.9 million for the Prior Successor Quarter, due to a combination of a 47% increase in oil equivalent pricing and a 12% increase in oil equivalent sales volumes. In addition to the overall increase due to operations, there was an increase of $2.7 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.

28

Table of Contents


The following table summarizes our operating expenses for the periods indicated:
 
Successor
 
Three Months Ended September 30, 2018
 
Three Months Ended September 30, 2017
 
Change
 
Percent Change
Expenses:
 
 

 
 
 

 
 
 
 
 
Lease operating expense
$
7,951

 
$
9,643

 
$
(1,692
)
 
(18
)%
Gas plant and midstream operating expense
 
2,249

 
 
3,265

 
 
(1,016
)
 
(31
)%
Gathering, transportation, and processing
 
2,749

 
 

 
 
2,749

 
100
 %
Severance and ad valorem taxes
 
6,485

 
 
2,434

 
 
4,051

 
166
 %
Exploration
 
(6
)
 
 

 
 
(6
)
 
(100
)%
Depreciation, depletion, and amortization
 
10,987

 
 
7,350

 
 
3,637

 
49
 %
Abandonment and impairment of unproved properties
 
430

 
 

 
 
430

 
100