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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 June 30, 2020
OR
☐ Transition report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934

For the transition period from                     to                   
Commission file number 001-37697
 
CENTENNIAL RESOURCE DEVELOPMENT, INC.
(Exact Name of Registrant as Specified in its Charter)
 
Delaware
 
47-5381253
(State of Incorporation)
 
(I.R.S. Employer Identification No.)
1001 Seventeenth Street, Suite 1800
Denver, Colorado 80202
(Registrant’s telephone number, including area code): (720) 499-1400
Securities registered pursuant to Section 12(b) of the Act:
Title of each class
 
Trading Symbol(s)
 
Name of each exchange on which registered
Class A Common Stock, par value $0.0001 per share
 
CDEV
 
The NASDAQ Stock Market LLC
Indicate by check mark whether the registrant: (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ☒ No ☐
Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted 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 such files). Yes ☒ No ☐
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.
Large accelerated filer
 
Accelerated filer 
 
Non-accelerated filer

 
Smaller reporting company 
 
Emerging growth company
☒
 
☐
 
☐
 
☐
 
☐
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ☐ No ☒
As of July 31, 2020, there were 278,309,116 shares of Class A Common Stock, par value $0.0001 per share outstanding.
 


TABLE OF CONTENTS
 
 
 
Page
3
 
 
5
 
 
6
 
 
8
 
 
 
 
 
8
 
 
 
 
 
 
8
 
 
 
 
 
 
9
 
 
 
 
 
 
10
 
 
 
 
 
 
12
 
 
 
 
 
 
14
 
 
 
 
 
31
 
 
 
 
 
46
 
 
 
 
 
48
 
 
 
 
48
 
 
 
 
 
48
 
 
 
 
 
48
 
 
 
 
 
51
 
 
 
 
53


Table of Contents

GLOSSARY OF OIL AND NATURAL GAS TERMS
The following are abbreviations and definitions of certain terms used in this Quarterly Report on Form 10-Q, which are commonly used in the oil and natural gas industry:

Bbl. One stock tank barrel of 42 U.S. gallons liquid volume used herein in reference to crude oil, condensate or NGLs.

Bbl/d. One Bbl per day.

Boe. One barrel of oil equivalent, calculated by converting natural gas to oil equivalent barrels at a ratio of six Mcf of natural gas to one Bbl of oil. This is an energy content correlation and does not reflect a value or price relationship between the commodities.

Boe/d. One Boe per day.

Btu. One British thermal unit, which is the quantity of heat required to raise the temperature of a one-pound mass of water by one-degree Fahrenheit.

Completion. The process of preparing an oil and gas wellbore for production through the installation of permanent production equipment, as well as perforation and fracture stimulation to optimize production.
Development well. A well drilled within the proved area of an oil or natural gas reservoir to the depth of a stratigraphic horizon known to be productive.
Differential. An adjustment to the price of oil or natural gas from an established spot market price to reflect differences in the quality and/or location of oil or natural gas.
Exploratory well. A well drilled to find a new field or to find a new reservoir in a field previously found to be productive of oil or natural gas in another reservoir.
Field. An area consisting of a single reservoir or multiple reservoirs all grouped on, or related to, the same individual geological structural feature or stratigraphic condition. The field name refers to the surface area, although it may refer to both the surface and the underground productive formations.

Flush production. First yield from a flowing oil well during its most productive period after it is first completed and put online.

Formation. A layer of rock which has distinct characteristics that differs from nearby rock.

Horizontal drilling. A drilling technique used in certain formations where a well is drilled vertically to a certain depth and then drilled at a right angle within a specified interval.

ICE Brent. Brent crude oil traded on the Intercontinental Exchange, Inc. (ICE).

LIBOR. London Interbank Offered Rate.

MBbl. One thousand barrels of crude oil, condensate or NGLs.

MBoe. One thousand Boe.

Mcf. One thousand cubic feet of natural gas.

Mcf/d. One Mcf per day.

MMBtu. One million British thermal units.

MMcf. One million cubic feet of natural gas.

NGL. Natural gas liquids. These are naturally occurring substances found in natural gas, including ethane, butane, isobutane, propane and natural gasoline, that can be collectively removed from produced natural gas, separated into these substances and sold.


3
Table of Contents

NYMEX. The New York Mercantile Exchange.

Operator. The individual or company responsible for the development and/or production of an oil or natural gas well or lease.

Proved developed reserves. Reserves that can be expected to be recovered through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared with the cost of a new well.

Proved reserves. The estimated quantities of oil, NGLs and natural gas that geological and engineering data demonstrate with reasonable certainty to be commercially recoverable in future years from known reservoirs under existing economic and operating conditions.

Proved undeveloped reserves or PUD. Proved reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for completion or recompletion. 

Realized price. The cash market price less differentials.

Recompletion. The completion for production of an existing wellbore in another formation from that which the well has been previously completed.

Reserves. Estimated remaining quantities of oil and natural gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and natural gas or related substances to market and all permits and financing required to implement the project.

Reservoir. A porous and permeable underground formation containing a natural accumulation of producible oil and/or natural gas that is confined by impermeable rock or water barriers and is individual and separate from other reservoirs.

Royalty interest. An interest in an oil or gas property entitling the owner to shares of the production free of costs of exploration, development and production operations.

Spot market price. The cash market price without reduction for expected quality, transportation and demand adjustments.

Wellbore. The hole drilled by a drill bit that is equipped for oil and natural gas production once the well has been completed. Also called well or borehole.

Working interest. The interest in an oil and gas property (typically a leasehold interest) that gives the owner the right to drill, produce and conduct operations on the property and to a share of production, subject to all royalties and other burdens and to all costs of exploration, development and operations and all risks in connection therewith.

Workover. Operations on a producing well to restore or increase production.

WTI. West Texas Intermediate is a grade of crude oil used as a benchmark in oil pricing.

4
Table of Contents

GLOSSARY OF CERTAIN OTHER TERMS
The following are definitions of certain other terms that are used in this Quarterly Report on Form 10-Q:
Business Combination. The acquisition of approximately 89% of the outstanding membership interests in CRP from the Centennial Contributors, which closed on October 11, 2016, and the other transactions contemplated by the Contribution Agreement.
Centennial Contributors. The legacy owners of CRP, who sold approximately 89% of the outstanding membership interests in CRP to the Company in connection with the Business Combination. On April 2, 2020, the Centennial Contributors converted all of their remaining CRP Common Units (and corresponding shares of Class C Common Stock) for Class A Common Stock, which eliminated their entire ownership interest in CRP.
The Company, we, our or us. (i) Centennial Resource Development, Inc. and its consolidated subsidiaries including CRP, following the closing of the Business Combination and (ii) Silver Run Acquisition Corporation prior to the closing of the Business Combination.
Class A Common Stock. Our Class A Common Stock, par value $0.0001 per share.
Class C Common Stock. Our Class C Common Stock, par value $0.0001 per share, which was issued to the Centennial Contributors in connection with the Business Combination.
Contribution Agreement. The Contribution Agreement, dated as of July 6, 2016, among the Centennial Contributors, CRP and NewCo, as amended by Amendment No. 1 thereto, dated as of July 29, 2016, and the Joinder Agreement, dated as of October 7, 2016, by the Company.
CRP. Centennial Resource Production, LLC, a Delaware limited liability company.
CRP Common Units. The units representing common membership interests in CRP.
NewCo. New Centennial, LLC, a Delaware limited liability company controlled by affiliates of Riverstone.
Riverstone. Riverstone Investment Group LLC and its affiliates, including Silver Run Sponsor, LLC, a Delaware limited liability company, collectively.
Voting common stock. Our Class A Common Stock and Class C Common Stock.


5
Table of Contents

CAUTIONARY STATEMENT CONCERNING FORWARD-LOOKING STATEMENTS
This Quarterly Report on Form 10-Q (“Quarterly Report”) includes “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended (the “Securities Act”) and Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). All statements, other than statements of historical fact included in this Quarterly Report, regarding our strategy, future operations, financial position, estimated revenues and losses, projected costs, prospects, plans and objectives of management are forward-looking statements. When used in this Quarterly Report, the words “could,” “may,” “believe,” “anticipate,” “intend,” “estimate,” “expect,” “project,” “goal,” “plan,” “target” 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 expectations and assumptions about future events and are based on currently available information as to the outcome and timing of future events. When considering forward-looking statements, you should keep in mind the risk factors and other cautionary statements described under “Item 1A. Risk Factors” in this Quarterly Report and in our Annual Report on Form 10-K for the year ended December 31, 2019 (the “2019 Annual Report”) and the risk factors and other cautionary statements contained in our other filings with the United States Securities and Exchange Commission (“SEC”).
Forward-looking statements may include statements about:
•
volatility of oil, natural gas and NGL prices or a prolonged period of low oil, natural gas or NGL prices and the effects of actions by, or disputes among or between, members of the Organization of Petroleum Exporting Countries (“OPEC”), such as Saudi Arabia, and other oil and natural gas producing countries, such as Russia, with respect to production levels or other matters related to the price of oil;
•
the effects of excess supply of oil and natural gas resulting from the reduced demand caused by the COVID-19 pandemic and the actions by certain oil and natural gas producing countries;
•
our business strategy and future drilling plans; 
•
our reserves and our ability to replace the reserves we produce through drilling and property acquisitions; 
•
our drilling prospects, inventories, projects and programs; 
•
our financial strategy, liquidity and capital required for our development program; 
•
our realized oil, natural gas and NGL prices; 
•
the timing and amount of our future production of oil, natural gas and NGLs; 
•
our hedging strategy and results; 
•
our competition and government regulations; 
•
our ability to obtain permits and governmental approvals; 
•
our pending legal or environmental matters; 
•
the marketing and transportation of our oil, natural gas and NGLs; 
•
our leasehold or business acquisitions; 
•
cost of developing our properties;
•
our anticipated rate of return;
•
general economic conditions; 
•
credit markets; 
•
uncertainty regarding our future operating results; and 
•
our plans, objectives, expectations and intentions contained in this Quarterly Report that are not historical.
You should not place undue reliance on these forward-looking statements. These forward-looking statements are subject to a number of risks, uncertainties and assumptions, including but not limited to those risks described under “Item 1A. Risk Factors” in this Quarterly Report and in our 2019 Annual Report. Moreover, we operate in a very competitive and rapidly changing environment. New risks emerge from time to time. It is not possible for our management to predict all risks, nor can we assess the impact of all factors on our business or the extent to which any factor, or combination of factors, may cause actual results to differ materially from those contained in any forward-looking statements we may make.

6
Table of Contents

Reserve engineering is a process of estimating underground accumulations of oil and natural gas that cannot be measured in an exact way. The accuracy of any reserve estimate depends on the quality of available data, the interpretation of such data and price and cost assumptions made by reserve engineers. In addition, the results of drilling, testing and production activities may justify revisions of estimates that were made previously. If significant, such revisions would change the schedule of any further production and development drilling. Accordingly, reserve estimates may differ significantly from the quantities of oil and natural gas that are ultimately recovered.
Although we believe that our plans, intentions and expectations reflected in or suggested by the forward-looking statements we make in this Quarterly Report are reasonable, we can give no assurance that these plans, intentions or expectations will be achieved or occur, and actual results could differ materially and adversely from those anticipated or implied by the forward-looking statements.
All forward-looking statements, expressed or implied, included in this Quarterly Report are expressly qualified in their entirety by this cautionary statement. This cautionary statement should also be considered in connection with any subsequent written or oral forward-looking statements that we or persons acting on our behalf may issue.
All forward-looking statements, expressed or implied, are made only as of the date of this Quarterly Report. Except as otherwise required by applicable law, we disclaim any duty to update any forward-looking statements to reflect events or circumstances after the date of this Quarterly Report.



7
Table of Contents

PART I. FINANCIAL INFORMATION
Item 1.    Financial Statements
CENTENNIAL RESOURCE DEVELOPMENT, INC.
CONSOLIDATED BALANCE SHEETS (unaudited)
(in thousands, except share and per share amounts)
 
June 30, 2020
 
December 31, 2019
ASSETS
 
 
 
Current assets
 
 
 
Cash and cash equivalents
$
7,214

 
$
10,223

Accounts receivable, net
64,095

 
101,912

Prepaid and other current assets
6,319

 
7,994

Total current assets
77,628

 
120,129

Property and Equipment
 
 
 
Oil and natural gas properties, successful efforts method
 
 
 
Unproved properties
1,328,022

 
1,470,903

Proved properties
4,270,397

 
3,962,175

Accumulated depreciation, depletion and amortization
(1,715,604
)
 
(931,737)

Total oil and natural gas properties, net
3,882,815

 
4,501,341

Other property and equipment, net
13,765

 
14,612

Total property and equipment, net
3,896,580

 
4,515,953

Noncurrent assets
 
 
 
Operating lease right-of-use assets
4,801

 
11,841

Other noncurrent assets
41,877

 
40,365

TOTAL ASSETS
$
4,020,886

 
$
4,688,288

 
 
 
 
LIABILITIES AND EQUITY
 
 
 
Current liabilities
 
 
 
Accounts payable and accrued expenses
$
122,360

 
$
244,309

Derivative instruments
31,740

 
325

Operating lease liabilities
3,591

 
9,232

Other current liabilities
170

 
600

Total current liabilities
157,861

 
254,466

Noncurrent liabilities
 
 
 
Long-term debt, net
1,106,043

 
1,057,389

Asset retirement obligations
18,067

 
16,874

Deferred income taxes
2,589

 
85,504

Operating lease liabilities
1,783

 
3,354

Total liabilities
1,286,343

 
1,417,587

Commitments and contingencies (Note 11)


 


Shareholders’ equity
 
 
 
Preferred stock, $0.0001 par value, 1,000,000 shares authorized:
 
 
 
Series A: 1 share issued and outstanding
—

 
—

Common stock, $0.0001 par value, 620,000,000 shares authorized:
 
 
 
Class A: 282,209,347 shares issued and 277,283,494 shares outstanding at June 30, 2020 and 280,650,341 shares issued and 275,811,346 shares outstanding at December 31, 2019
28

 
28

Class C (Convertible): No shares issued and outstanding at June 30, 2020 and 1,034,119 shares issued and outstanding at December 31, 2019
—

 
—

Additional paid-in capital
2,994,832

 
2,975,756

Retained earnings (accumulated deficit)
(260,317
)
 
282,336

Total shareholders’ equity
2,734,543

 
3,258,120

Noncontrolling interest
—

 
12,581

Total equity
2,734,543

 
3,270,701

TOTAL LIABILITIES AND EQUITY
$
4,020,886

 
$
4,688,288

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

8

CENTENNIAL RESOURCE DEVELOPMENT, INC.
CONSOLIDATED STATEMENTS OF OPERATIONS (unaudited)
(in thousands, except per share data)
 
Three Months Ended June 30,
 
Six Months Ended June 30,
 
2020
 
2019
 
2020
 
2019
Operating revenues
 
 
 
 
 
 
 
Oil and gas sales
$
90,509

 
$
244,239

 
$
283,278

 
$
458,808

Operating expenses
 
 
 
 
 
 
 
Lease operating expenses
25,839

 
34,885

 
58,478

 
64,747

Severance and ad valorem taxes
5,696

 
17,186

 
22,269

 
33,306

Gathering, processing and transportation expenses
17,284

 
16,243

 
34,223

 
31,267

Depreciation, depletion and amortization
93,020

 
112,114

 
194,278

 
208,672

Impairment and abandonment expense
19,425

 
4,418

 
630,725

 
35,682

Exploration expense
4,051

 
3,861

 
8,060

 
6,377

General and administrative expenses
17,994

 
18,435

 
36,864

 
36,553

Total operating expenses
183,309

 
207,142

 
984,897

 
416,604

Net gain (loss) on sale of long-lived assets
(2
)
 
9

 
243

 
7

Income (loss) from operations
(92,802
)
 
37,106

 
(701,376
)
 
42,211

 
 
 
 
 
 
 
 
Other income (expense)
 
 
 
 
 
 
 
Interest expense
(17,371
)
 
(14,437
)
 
(33,792
)
 
(24,597
)
Gain on exchange of debt
143,443

 
—

 
143,443

 
—

Net gain (loss) on derivative instruments
(29,857
)
 
2,128

 
(38,362
)
 
(3,743
)
Other income (expense)
1

 
133

 
(52
)
 
259

Total other income (expense)
96,216

 
(12,176
)
 
71,237

 
(28,081
)
 
 
 
 
 
 
 
 
Income (loss) before income taxes
3,414

 
24,930

 
(630,139
)
 
14,130

Income tax (expense) benefit
1,916

 
(5,928
)
 
85,124

 
(3,665
)
Net income (loss)
5,330

 
19,002

 
(545,015
)
 
10,465

Less: Net (income) loss attributable to noncontrolling interest
—

 
(1,125
)
 
2,362

 
(700
)
Net income (loss) attributable to Class A Common Stock
$
5,330

 
$
17,877

 
$
(542,653
)
 
$
9,765

 
 
 
 
 


 


Income (loss) per share of Class A Common Stock:
 
 
 
 
 
 
 
Basic
$
0.02

 
$
0.07

 
$
(1.96
)
 
$
0.04

Diluted
$
0.02

 
$
0.07

 
$
(1.96
)
 
$
0.04

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


9

CENTENNIAL RESOURCE DEVELOPMENT, INC.
CONSOLIDATED STATEMENTS OF CASH FLOWS (unaudited)
(in thousands)
 
Six Months Ended June 30,
 
2020

2019
Cash flows from operating activities:
 
 
 
Net income (loss)
$
(545,015
)
 
$
10,465

Adjustments to reconcile net income to net cash provided by operating activities:
 
 
 
Depreciation, depletion and amortization
194,278

 
208,672

Stock-based compensation expense
11,136

 
13,241

Impairment and abandonment expense
630,725

 
35,682

Deferred tax expense (benefit)
(85,124
)
 
3,665

Net (gain) loss on sale of long-lived assets
(243
)
 
(7
)
Non-cash portion of derivative (gain) loss
31,415

 
9,754

Amortization of debt issuance costs and discount
2,334

 
1,287

Gain on exchange of debt
(143,443
)
 
—

Changes in operating assets and liabilities:
 
 
 
(Increase) decrease in accounts receivable
36,065

 
(22,751
)
(Increase) decrease in prepaid and other assets
41

 
(154
)
Increase (decrease) in accounts payable and other liabilities
(47,666
)
 
20,340

Net cash provided by operating activities
84,503

 
280,194

Cash flows from investing activities:
 
 
 
Acquisition of oil and natural gas properties
(6,113
)
 
(42,264
)
Drilling and development capital expenditures
(271,389
)
 
(437,912
)
Purchases of other property and equipment
(811
)
 
(4,263
)
Proceeds from sales of oil and natural gas properties
1,263

 
25,919

Net cash used in investing activities
(277,050
)
 
(458,520
)
Cash flows from financing activities:
 
 
 
Proceeds from borrowings under revolving credit facility
385,000

 
155,000

Repayment of borrowings under revolving credit facility
(190,000
)
 
(455,000
)
Proceeds from issuance of senior notes
—

 
496,175

Debt exchange and debt issuance costs
(5,141
)
 
(7,200
)
Restricted stock used for tax withholdings
(301
)
 
(332
)
Net cash provided by financing activities
189,558

 
188,643

Net increase (decrease) in cash, cash equivalents and restricted cash
(2,989
)
 
10,317

Cash, cash equivalents and restricted cash, beginning of period
15,543

 
21,422

Cash, cash equivalents and restricted cash, end of period
$
12,554

 
$
31,739

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

10

CENTENNIAL RESOURCE DEVELOPMENT, INC.
CONSOLIDATED STATEMENTS OF CASH FLOWS (unaudited) (continued)
(in thousands)
 
Six Months Ended June 30,
 
2020

2019
Supplemental cash flow information
 
 
 
Cash paid for interest
$
36,618

 
$
15,799

Operating lease liability payments:
 
 
 
Cash used in operating activities
4,252

 
11,487

Cash used in investing activities
2,019

 
9,906

Supplemental non-cash activity
 
 
 
Accrued capital expenditures included in accounts payable and accrued expenses
$
22,474

 
$
128,807

Asset retirement obligations incurred, including revisions to estimates
542

 
714

Right-of-use assets recognized (derecognized) with offsetting operating lease liabilities
(3,454
)
 
35,267

Change in Senior Notes from debt exchange
 
 
 
Senior Secured Notes issued in the debt exchange, net of debt discount
106,030

 
—

2026 Senior Notes extinguished in the debt exchange, net of unamortized debt issue costs
(108,632
)
 
—

2027 Senior Notes extinguished in the debt exchange, net of unamortized discount and debt issue costs
(140,840
)
 
—

Reconciliation of cash, cash equivalents and restricted cash presented on the Consolidated Statements of Cash Flows for the periods presented:
 
Six Months Ended June 30,
 
2020
 
2019
Cash and cash equivalents
$
7,214

 
$
28,444

Restricted cash(1)
5,340

 
3,295

Total cash, cash equivalents and restricted cash
$
12,554

 
$
31,739

 
(1) 
Included in Prepaid and other current assets and Other noncurrent assets line items in the Consolidated Balance Sheets.


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


11

CENTENNIAL RESOURCE DEVELOPMENT, INC.
CONSOLIDATED STATEMENTS OF SHAREHOLDERS’ EQUITY (unaudited)
(in thousands)


 
Common Stock
 
Preferred Stock
 
 
 
 
 
 
 
 
 
 
 
Class A
 
Class C
 
Series A
 
Additional Paid-In Capital
 
Retained Earnings (Accumulated Deficit)
 
Total Shareholders’ Equity
 
Non-controlling Interest
 
Total Equity
 
Shares

Amount

Shares

Amount

Shares

Amount
 
 
 
 
 
Balance at December 31, 2019
280,650

 
$
28

 
1,034

 
$
—

 
—

 
$
—

 
$
2,975,756

 
$
282,336

 
$
3,258,120

 
$
12,581

 
$
3,270,701

Restricted stock issued
1,305

 
—

 
—

 
—

 
—

 
—

 
—

 
—

 
—

 
—

 
—

Restricted stock forfeited
(406
)
 
—

 
—

 
—

 
—

 
—

 
—

 
—

 
—

 
—

 
—

Restricted stock used for tax withholding
(78
)
 
—

 
—

 
—

 
—

 
—

 
(208
)
 
—

 
(208
)
 
—

 
(208
)
Issuance of Class A common stock under Employee Stock Purchase Plan
59

 
—

 
—

 
—

 
—

 
—

 
230

 
—

 
230

 
—

 
230

Stock-based compensation
—

 
—

 
—

 
—

 
—

 
—

 
6,409

 
—

 
6,409

 
—

 
6,409

Net income (loss)
—

 
—

 
—

 
—

 
—

 
—

 
—

 
(547,983
)
 
(547,983
)
 
(2,362
)
 
(550,345
)
Balance at March 31, 2020
281,530

 
28

 
1,034

 
—

 
—

 
—

 
2,982,187

 
(265,647
)
 
2,716,568

 
10,219

 
2,726,787

Restricted stock issued
80

 
—

 
—

 
—

 
—

 
—

 
—

 
—

 
—

 
—

 
—

Restricted stock forfeited
(352
)
 
—

 
—

 
—

 
—

 
—

 
—

 
—

 
—

 
—

 
—

Restricted stock used for tax withholding
(83
)
 
—

 
—

 
—

 
—

 
—

 
(93
)
 
—

 
(93
)
 
—

 
(93
)
Stock-based compensation
—

 
—

 
—

 
—

 
—

 
—

 
4,727

 
—

 
4,727

 
—

 
4,727

Conversion of common stock from Class C to Class A, net of tax
1,034

 
—

 
(1,034
)
 
—

 
—

 
—

 
8,011

 
—

 
8,011

 
(10,219
)
 
(2,208
)
Net income (loss)
—

 
—

 
—

 
—

 
—

 
—

 
—

 
5,330

 
5,330

 
—

 
5,330

Balance at June 30, 2020
282,209

 
$
28

 
—

 
$
—

 
—

 
$
—

 
$
2,994,832

 
$
(260,317
)
 
$
2,734,543

 
$
—

 
$
2,734,543


12

CENTENNIAL RESOURCE DEVELOPMENT, INC.
CONSOLIDATED STATEMENTS OF SHAREHOLDERS’ EQUITY (unaudited) (continued)
(in thousands)
 
Common Stock
 
Preferred Stock
 
 
 
 
 
 
 
 
 
 
 
Class A
 
Class C
 
Series A
 
Additional Paid-In Capital
 
Retained Earnings (Accumulated Deficit)
 
Total Shareholders’ Equity
 
Non-controlling Interest
 
Total Equity
 
Shares
 
Amount
 
Shares
 
Amount
 
Shares
 
Amount
 
 
 
 
 
Balance at December 31, 2018
265,859

 
$
27

 
12,003

 
$
1

 
—

 
$
—

 
$
2,833,611

 
$
266,538

 
$
3,100,177

 
$
143,692

 
$
3,243,869

Restricted stock issued
436

 
—

 
—

 
—

 
—

 
—

 
—

 
—

 
—

 
—

 
—

Restricted stock forfeited
—

 
—

 
—

 
—

 
—

 
—

 
—

 
—

 
—

 
—

 
—

Restricted stock used for tax withholding
(24
)
 
—

 
—

 
—

 
—

 
—

 
(291
)
 
—

 
(291
)
 
—

 
(291
)
Stock-based compensation
—

 
—

 
—

 
—

 
—

 

 
6,483

 
—

 
6,483

 
—

 
6,483

Net income (loss)
—

 
—

 
—

 
—

 
—

 
—

 
—

 
(8,112
)
 
(8,112
)
 
(425
)
 
(8,537
)
Balance at March 31, 2019
266,271

 
27

 
12,003

 
1

 
—

 
—

 
2,839,803

 
258,426

 
3,098,257

 
143,267

 
3,241,524

Restricted stock issued
4

 
—

 
—

 
—

 
—

 
—

 
—

 
—

 
—

 
—

 
—

Restricted stock forfeited
(16
)
 
—

 
—

 
—

 
—

 
—

 
—

 
—

 
—

 
—

 
—

Restricted stock used for tax withholding
(4
)
 
—

 
—

 
—

 
—

 
—

 
(41
)
 
—

 
(41
)
 
—

 
(41
)
Stock-based compensation
—

 
—

 
—

 
—

 
—

 
—

 
6,758

 
—

 
6,758

 
—

 
6,758

Net income (loss)
—

 
—

 
—

 
—

 
—

 
—

 
—

 
17,877

 
17,877

 
1,125

 
19,002

Balance at June 30, 2019
266,255

 
$
27

 
12,003

 
$
1

 
—

 
$
—

 
$
2,846,520

 
$
276,303

 
$
3,122,851

 
$
144,392

 
$
3,267,243


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








13

CENTENNIAL RESOURCE DEVELOPMENT, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
Note 1—Basis of Presentation and Summary of Significant Accounting Policies
Description of Business
Centennial Resource Development, Inc. is an independent oil and natural gas company focused on the development of unconventional oil and associated liquids-rich natural gas reserves in the Permian Basin. The Company’s assets are concentrated in the Delaware Basin, a sub-basin of the Permian Basin, and its properties consist of large, contiguous acreage blocks located in West Texas and New Mexico. Unless otherwise specified or the context otherwise requires, all references in these notes to “Centennial” or the “Company” are to Centennial Resource Development, Inc. and its consolidated subsidiary, Centennial Resource Production, LLC (“CRP”).
Principles of Consolidation and Basis of Presentation
The accompanying unaudited consolidated financial statements have been prepared in accordance with generally accepted accounting principles in the United States of America (“GAAP”) and the rules and regulations of the United States Securities and Exchange Commission (“SEC”) for interim financial reporting. Accordingly, certain disclosures normally included in an Annual Report on Form 10-K have been omitted. The consolidated financial statements and related notes included in this Quarterly Report should be read in conjunction with the Company’s consolidated financial statements and related notes included in the Company’s Annual Report on Form 10-K for the period ended December 31, 2019 (the “2019 Annual Report”). Except as disclosed herein, there have been no material changes to the information disclosed in the notes to the consolidated financial statements included in the Company’s 2019 Annual Report.
In the opinion of management, all normal, recurring adjustments and accruals considered necessary to present fairly, in all material respects, the Company’s interim financial results have been included. Operating results for the periods presented are not necessarily indicative of expected results for the full year.
The consolidated financial statements include the accounts of the Company and its subsidiary CRP, and CRP’s wholly-owned subsidiaries. Noncontrolling interest represents third-party ownership in CRP and is presented as a component of equity. As of December 31, 2019, the noncontrolling interest ownership of CRP was 0.4%.
On April 2, 2020, the legacy owners of CRP converted all of their remaining 1,034,119 CRP Common Units (and corresponding shares of Class C Common Stock) into Class A Common Stock (the “Conversion”), which eliminated the noncontrolling interest ownership in CRP. As a result, CRP was a wholly-owned subsidiary of Centennial Resource Development, Inc. for the three month period ended June 30, 2020. No cash proceeds were received by the Company in connection with the Conversion, and deferred tax expense of $2.2 million was recorded in equity with an offsetting deferred tax liability for the same amount, upon conversion.
Use of Estimates
The preparation of the Company’s consolidated financial statements requires the Company’s management to make various assumptions, judgments and estimates to determine the reported amounts of assets, liabilities, revenues and expenses, and the disclosures of commitments and contingencies. Changes in these assumptions, judgments and estimates will occur as a result of the passage of time and the occurrence of future events, and accordingly, actual results could differ from amounts previously established.
The more significant areas requiring the use of assumptions, judgments and estimates include: (i) oil and natural gas reserves; (ii) cash flow estimates used in impairment tests for long-lived assets; (iii) impairment expense of unproved properties; (iv) depreciation, depletion and amortization; (v) asset retirement obligations; (vi) determining fair value and allocating purchase price in connection with business combinations and asset acquisitions; (vii) accrued revenues and related receivables; (viii) accrued liabilities; (ix) valuation of derivatives; and (x) deferred income taxes.
Income Taxes
Historically, CRP has been treated as a partnership for U.S. federal and most applicable state and local income tax purposes. As a partnership, CRP was not subject to U.S. federal and certain state and local income taxes, and any taxable income or loss generated by CRP was passed through to and included in the taxable income or loss of its members, including Centennial Resource Development, Inc., on a pro rata basis. Following the Conversion, CRP is no longer a partnership for tax purposes. As a result, the deferred tax assets and liabilities previously recorded within the partnership, and previously reported by the Company as a net deferred tax balance related to its investment in the CRP partnership, are now directly included within the Company’s

14
CENTENNIAL RESOURCE DEVELOPMENT, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)


deferred tax assets and liabilities. Further, the Company is now subject to U.S. federal and applicable state and local income taxes for its entire consolidated taxable income or loss.
Income tax expense recognized during interim periods is based on applying an estimated annual effective income tax rate to the Company’s year-to-date income, plus any significant unusual or infrequently occurring items which are recorded in the interim period. The computation of the annual estimated effective tax rate at each interim period requires certain estimates and significant judgment including, but not limited to, the expected operating income for the year, projections of the proportion of income earned and taxed in various state jurisdictions, permanent and temporary differences and the likelihood of recovering deferred tax assets generated. The accounting estimates used to compute the provision for income taxes may change as new events occur, additional information becomes known or as the tax environment changes.
During the first half of 2020, the Company determined that it is more-likely-than-not that a portion of its deferred tax assets will not be realized. Accordingly, a valuation allowance against its deferred tax assets in the amount of $49.7 million was recognized as of June 30, 2020, which caused the Company’s provision for income taxes for the three and six months ended June 30, 2020 to differ from the amounts that would be provided by applying the statutory U.S. federal income tax rate of 21% to pre-tax book loss.
Risks and Uncertainties
The prices received for oil, natural gas and NGL production heavily influence the Company’s revenue, profitability, liquidity, access to capital, future rate of growth and carrying value of its properties. Oil, natural gas and NGLs are commodities, and their prices have been volatile in response to recent changes in global and domestic supply, the global COVID-19 pandemic and demand, and market uncertainty. The Company generally funds its operations and capital expenditures with its cash flows from operations, borrowings under CRP’s credit agreement, and offerings of debt and equity securities. The Company expects to be able to fund its operations, planned capital expenditures and working capital requirements during the next 12 months and the foreseeable future. However, continued volatility of oil and gas prices could have an adverse effect on the Company’s future business, financial condition, results of operations, operating cash flows, liquidity, production levels and quantities of oil and gas reserves that may be economically produced, which could in turn impact the Company’s ability to comply with the financial covenants under its borrowing agreements and could also limit the amount of borrowings available to fund the Company’s capital expenditures and potential acquisitions. Additionally, if forward prices decline, the Company could incur additional impairments of its oil and gas assets.
Note 2—Property Divestiture
On February 24, 2020, the Company entered into a purchase and sale agreement (the “Agreement”) to sell certain of its water disposal assets. On May 15, 2020, the Agreement was terminated after the purchaser failed to close the transaction as set forth in the Agreement.
The purchaser deposited $10.0 million of cash in an escrow account (the “Deposit”) which, in the event of termination, was to be distributed to the Company or the purchaser in accordance with the remedy provisions of the Agreement. Centennial believes it has a right to receive the Deposit, pursuant to the terms of the Agreement. However, the purchaser advised the Company that it disputes this position, and as a result, the distribution of the Deposit is under ongoing litigation between the Company and the purchaser.
Note 3—Accounts Receivable, Accounts Payable and Accrued Expenses
Accounts receivable are comprised of the following:
(in thousands)
June 30, 2020

December 31, 2019
Accrued oil and gas sales receivable, net
$
41,525


$
76,578

Joint interest billings, net
22,451


25,136

Other
119


198

Accounts receivable, net
$
64,095


$
101,912



15
CENTENNIAL RESOURCE DEVELOPMENT, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)


Accounts payable and accrued expenses are comprised of the following:
(in thousands)
June 30, 2020

December 31, 2019
Accounts payable
$
8,754


$
21,484

Accrued capital expenditures
18,765


83,002

Revenues payable
42,633


82,539

Accrued interest
15,466


19,405

Accrued derivative settlements payable
11,569

 
—

Accrued employee compensation and benefits
6,167


12,979

Accrued expenses and other
19,006


24,900

Accounts payable and accrued expenses
$
122,360


$
244,309


Note 4—Long-Term Debt
The following table provides information about the Company’s long-term debt as of the dates indicated:
(in thousands)
June 30, 2020
 
December 31, 2019
Credit Facility due 2023
$
370,000

 
$
175,000

 
 
 
 
8.00% Senior Secured Notes due 2025
127,073

 
—

5.375% Senior Notes due 2026
289,448

 
400,000

6.875% Senior Notes due 2027
356,351

 
500,000

Unamortized debt issuance costs on Senior Notes
(13,646
)
 
(14,061
)
Unamortized debt discount
(23,183
)
 
(3,550
)
Senior Notes, net
736,043

 
882,389

 
 
 
 
Total long-term debt, net
$
1,106,043

 
$
1,057,389


Credit Agreement
CRP, the Company’s consolidated subsidiary, has a credit agreement with a syndicate of banks that provides for a five-year secured revolving credit facility, maturing on May 4, 2023 (the “Credit Agreement”). On May 1, 2020, CRP, as borrower, and the Company, as parent guarantor, entered into the second and third amendments to the Credit Agreement (the “2020 Amendments”), which, among other things, established a new borrowing base and level of elected commitments of $700.0 million. The 2020 Amendments that the lenders approved also permitted the issuance of the Senior Secured Notes in connection with the Debt Exchange (defined below), and they implemented an availability blocker equal to 25% of the newly issued amount of Senior Secured Notes. As of June 30, 2020, the Company had $370.0 million in borrowings outstanding and $290.0 million in available borrowing capacity, which was net of $8.2 million in letters of credit outstanding and the availability blocker of $31.8 million.
The amount available to be borrowed under CRP’s Credit Agreement is equal to the lesser of (i) the borrowing base less the availability blocker, (ii) aggregate elected commitments, which was set at $700.0 million pursuant to the 2020 Amendments, or (iii) $1.5 billion. The borrowing base is redetermined semi-annually in the spring and fall by the lenders in their sole discretion. It also allows for two optional borrowing base redeterminations on January 1 and July 1. The borrowing base depends on, among other things, the quantities of CRP’s proved oil and natural gas reserves, estimated cash flows from these reserves, and the Company’s commodity hedge positions. Upon a redetermination of the borrowing base, if actual borrowings exceed the revised borrowing capacity, CRP could be required to immediately repay a portion of its debt outstanding. Borrowings under the Credit Agreement are guaranteed by certain of CRP’s subsidiaries and the Company.
Borrowings under the Credit Agreement may be base rate loans or LIBOR loans. Interest is payable quarterly for base rate loans and at the end of the applicable interest period for LIBOR loans. LIBOR loans bear interest at LIBOR (adjusted for statutory reserve requirements and subject to 1% floor) plus an applicable margin, which ranged from 200 to 300 basis points as of June 30, 2020, depending on the percentage of the borrowing base utilized. Base rate loans bear interest at a rate per annum equal to the greatest of: (i) the agent bank’s prime rate; (ii) the federal funds effective rate plus 50 basis points; or (iii) the adjusted LIBOR rate for a one-month interest period plus 100 basis points, plus an applicable margin, which ranged from 100 to 200 basis

16
CENTENNIAL RESOURCE DEVELOPMENT, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)


points as of June 30, 2020, depending on the percentage of the borrowing base utilized. CRP also pays a commitment fee of 37.5 to 50 basis points on unused amounts under its facility.
CRP’s Credit Agreement contains restrictive covenants that limit its ability to, among other things: (i) incur additional indebtedness; (ii) make investments and loans; (iii) enter into mergers; (iv) make or declare dividends; (v) enter into commodity hedges exceeding a specified percentage of the Company’s expected production; (vi) enter into interest rate hedges exceeding a specified percentage of its outstanding indebtedness; (vii) incur liens; (viii) sell assets; and (ix) engage in transactions with affiliates.
CRP’s Credit Agreement also requires it to maintain compliance with the following financial ratios:
(i) a current ratio, which is the ratio of CRP’s consolidated current assets (including unused commitments under its revolving credit facility and excluding non-cash derivative assets and certain restricted cash) to its consolidated current liabilities (excluding any current portion of long-term debt due under the credit agreement and non-cash derivative liabilities), of not less than 1.0 to 1.0;
(ii) a first lien leverage ratio, as defined within the Credit Agreement as the ratio of first lien debt to EBITDAX for the rolling four fiscal quarter period, which may not exceed 2.75 to 1.00 beginning with the quarter ending June 30, 2020 and extending through the quarter ending December 31, 2021, after which the maximum ratio shall decrease to 2.50 to 1.00 for each of the quarters ending in 2022; and
(iii) a leverage ratio, as also defined in the Credit Agreement as the ratio of total funded debt to consolidated EBITDAX for the rolling four fiscal quarter period. Pursuant to the 2020 Amendments, the leverage ratio is suspended until March 31, 2022, at which time, the ratio may not exceed 5.00 to 1.00, with such maximum ratio declining at a rate of 0.25 for each succeeding quarter until March 31, 2023 when the ratio is set at not greater than 4.0 to 1.0.
CRP was in compliance with the covenants and the financial ratios described above as of June 30, 2020 and through the filing of this Quarterly Report.
Senior Unsecured Note Debt Exchange
On May 22, 2020, CRP completed its private exchange of debt pursuant to which a $254.2 million aggregate principal amount of Senior Unsecured Notes (defined below) was validly tendered and exchanged by certain eligible bondholders for consideration consisting of $127.1 million aggregate principal amount (the “Debt Exchange”) of newly issued 8.00% second lien senior secured notes due 2025 (the “Senior Secured Notes”).
Whether a debt exchange should be accounted for pursuant to Financial Accounting Standards Board’s Accounting Standard Codification (“ASC”) Topic 470-60, Troubled Debt Restructurings by Debtors, or pursuant to ASC Topic 470-50, Modifications and Extinguishments, requires judgments to be made with respect to whether or not an entity is experiencing financial difficulty. As it was determined that Centennial was not experiencing financial difficulty and could obtain funds at market rates it could afford (i.e. non-investment grade but nontroubled debtor rates), the Company’s Debt Exchange was accounted for as an extinguishment of debt in accordance with ASC 470-50. As a result, a gain on the exchange of debt of $143.4 million was recognized in the Consolidated Statement of Operations, which consisted of the carrying values of the Senior Unsecured Notes exchanged less the aggregate principal amount of new Senior Secured Notes issued, net of their associated debt discount of $21.0 million (which was based on the notes’ estimated fair value on the exchange date).
Senior Secured Notes
In connection with the Debt Exchange, on May 22, 2020, the Company issued $127.1 million aggregate principal amount of Senior Secured Notes. The Senior Secured Notes were recorded at their fair value on the date of issuance equal to 83.44% of par (a debt discount of $21.0 million) and net of their associated debt issuance costs of $4.2 million. The Senior Secured Notes bear interest at an annual rate of 8.00% and are due on June 1, 2025. Interest is payable semi-annually in arrears on each June 1 and December 1, commencing on December 1, 2020.
The Senior Secured Notes are guaranteed, subject to certain exceptions, by the Company and each of CRP’s subsidiaries and are secured on a second-priority basis (subject in priority only to certain exceptions) by substantially all of the assets of CRP and the Company, including deposit accounts and substantially all proved reserves and undeveloped acreage.
The Company has the option to redeem all (but not less than all) of the Senior Secured Notes, at any time prior to May 22, 2021 on a single occasion, at a redemption price equal to 100% of the principal amount, plus accrued and unpaid interest to the date of redemption, if such redemption is made entirely with proceeds from equity offerings or the issuance of unsecured indebtedness.

17
CENTENNIAL RESOURCE DEVELOPMENT, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)


At any time prior to June 1, 2022, the Company has the option to redeem the Senior Secured Notes, in whole or in part, at a redemption price equal to 100% of the principal amount of the Senior Secured Notes redeemed plus accrued and unpaid interest and a “make-whole” premium. The Senior Secured Notes are redeemable at the Company’s option, in whole or in part, at any time on or after June 1, 2022, at specified redemption prices, together with accrued and unpaid interest. In addition, at any time prior to June 1, 2022, the Company may redeem up to 35% of the aggregate principal amount of each of the Senior Secured Notes, including any permitted additional Senior Secured Notes, with an amount of cash not greater than the net proceeds of certain equity offerings at a redemption price equal to 108% of the principal amount of such Senior Secured Notes, plus any accrued and unpaid interest to, but excluding, the redemption date.
Senior Unsecured Notes
On March 15, 2019, CRP issued $500.0 million of 6.875% senior notes due 2027 (the “2027 Senior Notes”) in a 144A private placement at a price equal to 99.235% of par that resulted in net proceeds to CRP of $489.0 million, after deducting the original issuance discount of $3.8 million and debt issuance costs of $7.2 million. Interest is payable on the 2027 Senior Notes semi-annually in arrears on each April 1 and October 1, which commenced on October 1, 2019. In May 2020 in connection with the Debt Exchange, $143.7 million aggregate principal amount of the 2027 Senior Notes was exchanged for Senior Secured Notes. As of June 30, 2020, the remaining aggregate principal amount of 2027 Senior Notes outstanding was $356.4 million.
On November 30, 2017, CRP issued at par $400.0 million of 5.375% senior notes due 2026 (the “2026 Senior Notes” and collectively with the 2027 Senior Notes, the “Senior Unsecured Notes”) in a 144A private placement that resulted in net proceeds to CRP of $391.0 million, after deducting $9.0 million in debt issuance costs. Interest is payable on the 2026 Senior Notes semi-annually in arrears on each January 15 and July 15, which commenced on July 15, 2018. In May 2020 in connection with the Debt Exchange, $110.6 million aggregate principal amount of the 2026 Senior Notes was exchanged for Senior Secured Notes. As of June 30, 2020, the remaining aggregate principal amount of 2026 Senior Notes outstanding was $289.4 million.
The Senior Unsecured Notes are fully and unconditionally guaranteed on a senior unsecured basis by the Company and each of CRP’s current subsidiaries that guarantee CRP’s revolving credit facility.
At any time prior to January 15, 2021 (for the 2026 Senior Notes) and April 1, 2022 (for the 2027 Senior Notes), the “Optional Redemption Dates,” CRP may, on any one or more occasions, redeem up to 35% of the aggregate principal amount of either series of Senior Unsecured Notes with an amount of cash not greater than the net cash proceeds of certain equity offerings at a redemption price equal to 105.375% (for the 2026 Senior Notes) and 106.875% (for the 2027 Senior Notes) of the principal amount of the Senior Unsecured Notes of the applicable series redeemed, plus any accrued and unpaid interest to the date of redemption; provided that at least 65% of the aggregate principal amount of each such series of Senior Unsecured Notes remains outstanding immediately after such redemption, and the redemption occurs within 180 days of the closing date of such equity offering.
At any time prior to the Optional Redemption Dates, CRP may, on any one or more occasions, redeem all or a part of the Senior Unsecured Notes at a redemption price equal to 100% of the principal amount of the Senior Unsecured Notes redeemed, plus a “make-whole” premium, and any accrued and unpaid interest as of the date of redemption. On and after the Optional Redemption Dates, CRP may redeem the Senior Unsecured Notes, in whole or in part, at redemption prices expressed as percentages of principal amount plus accrued and unpaid interest to the redemption date.
Senior Notes
The following section discusses the general terms of the indentures applicable to the Company’s Senior Unsecured Notes and the Senior Secured Notes (collectively, the “Senior Notes”).
The indentures governing the Senior Notes contain covenants that, among other things and subject to certain exceptions and qualifications, limit CRP’s ability and the ability of CRP’s restricted subsidiaries to: (i) incur or guarantee additional indebtedness or issue certain types of preferred stock; (ii) pay dividends on capital stock or redeem, repurchase or retire capital stock or subordinated indebtedness; (iii) transfer or sell assets; (iv) make investments; (v) create certain liens; (vi) enter into agreements that restrict dividends or other payments from their subsidiaries to them; (vii) consolidate, merge or transfer all or substantially all of their assets; (viii) engage in transactions with affiliates; and (ix) create unrestricted subsidiaries. CRP was in compliance with these covenants as of June 30, 2020 and through the filing of this Quarterly Report.
Upon an Event of Default (as defined in the indentures governing the Senior Notes), the trustee or the holders of at least 25% of the aggregate principal amount of then outstanding Senior Notes may declare the Senior Notes immediately due and payable. In addition, a default resulting from certain events of bankruptcy or insolvency with respect to CRP, any restricted subsidiary of CRP that is a significant subsidiary, or any group of restricted subsidiaries that, taken together, would constitute a significant subsidiary, will automatically cause all outstanding Senior Notes to become due and payable.

18
CENTENNIAL RESOURCE DEVELOPMENT, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)


If CRP experiences certain defined changes of control (and, in some cases, followed by a ratings decline), each holder of the Senior Notes may require CRP to repurchase all or a portion of its Senior Notes for cash at a price equal to 101% of the aggregate principal amount of such Senior Notes, plus any accrued but unpaid interest to the date of repurchase.
Note 5—Asset Retirement Obligations
The following table summarizes changes in the Company’s asset retirement obligations (“ARO”) associated with its working interests in oil and gas properties for the six months ended June 30, 2020:
(in thousands)
 
Asset retirement obligations, beginning of period
$
16,874

Liabilities incurred and acquired
630

Liabilities divested and settled
(34
)
Accretion expense
538

Revisions to estimated cash flows
59

Asset retirement obligations, end of period
$
18,067


ARO reflect the present value of the estimated future costs associated with the plugging and abandonment of oil and natural gas wells, removal of equipment and facilities from leased acreage and land restoration in accordance with applicable local, state and federal laws. Inherent in the fair value calculation of ARO are numerous assumptions and judgments including the ultimate plug and abandonment settlement amounts, inflation factors, credit adjusted discount rates and timing of settlement. To the extent future revisions to these assumptions impact the value of the existing ARO liability, a corresponding offsetting adjustment is made to the oil and gas property balance. Changes in the liability due to the passage of time are recognized as an increase in the carrying amount of the liability and as accretion expense.
Note 6—Stock-Based Compensation
On October 7, 2016, the stockholders of the Company approved the Centennial Resource Development, Inc. 2016 Long Term Incentive Plan (the “LTIP”), which authorized an aggregate of 16,500,000 shares of Class A Common Stock for issuance. On April 29, 2020, the stockholders of the Company approved the amended and restated LTIP, which, among other things, increased the number of shares of Class A Common Stock authorized for issuance by 8,250,000 shares. As of June 30, 2020, the Company had 14,763,345 shares of Class A Common Stock available for future grants. The LTIP provides for grants of restricted stock, stock options (including incentive stock options and nonqualified stock options), restricted stock units, stock appreciation rights and other stock or cash-based awards.
During the three months ended June 30, 2020, as a result of the decline in crude oil and natural gas prices, ongoing uncertainty regarding the oil supply-demand macro environment and the related suspension of the Company’s drilling and completion activities, the Company implemented a reduction to its workforce. In connection with this reduction, the Compensation Committee of the Company’s Board of Directors approved an accelerated partial vesting of certain unvested stock options and restricted stock awards held by 32 of the terminated employees. The acceleration changed the terms of the vesting conditions and are therefore treated as modifications in accordance with ASC Topic 718, Compensation-Stock Compensation. The modification resulted in a decrease to total stock-based compensation expense of $2.5 million associated with the decrease in the fair value of the modified awards compared to the original awards’ fair value. The shares and options that were accelerated are included within the vested line item in the below tables.
Stock-based compensation expense is recognized within both General and administrative expenses and Exploration expense in the Consolidated Statements of Operations. The Company accounts for forfeitures of awards granted under the LTIP as they occur in determining compensation expense.

19
CENTENNIAL RESOURCE DEVELOPMENT, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)


The following table summarizes stock-based compensation expense recognized for the periods presented:
 
Three Months Ended June 30,
 
Six Months Ended June 30,
(in thousands)
2020
 
2019
 
2020
 
2019
Restricted stock awards
$
3,387

 
$
3,408

 
$
7,741

 
$
6,590

Stock option awards
291

 
2,625

 
1,275

 
5,209

Performance stock units
1,003

 
725

 
2,006

 
1,442

Other stock-based compensation expense(1)
46

 
—

 
114

 
—

Total stock-based compensation expense
$
4,727

 
$
6,758

 
$
11,136

 
$
13,241

 
(1)  
Includes expenses related to the Company’s Employee Stock Purchase Plan (the “ESPP”). In May 2019, an aggregate of 2,000,000 shares were authorized by stockholders for issuance under the ESPP, which became effective on July 1, 2019. As of June 30, 2020, the Company had 1,940,801 shares of Class A Common Stock available for future issuance.
Restricted Stock
The following table provides information about restricted stock activity during the six months ended June 30, 2020:
 
Awards
 
Weighted Average Grant-Date Fair Value
Unvested balance as of December 31, 2019
4,838,996

 
$
8.51

Granted
1,385,235

 
2.53

Vested
(540,402
)
 
8.52

Forfeited
(757,975
)
 
5.81

Unvested balance as of June 30, 2020
4,925,854

 
6.90


The Company grants service-based restricted stock awards to executive officers and employees, which vest ratably over a three-year service period, and to directors, which vest over a one-year service period. Compensation cost for the service-based restricted stock awards is based on the closing market price of the Company’s Class A common stock on the grant date, and such costs are recognized ratably over the applicable vesting period. The weighted average grant-date fair value for restricted stock awards granted during the period was $2.53 and $12.48 per share for the six months ended June 30, 2020 and 2019, respectively. The total fair value of restricted stock awards that vested during the six months ended June 30, 2020 and 2019 was $4.6 million and $1.5 million, respectively, and includes awards with vesting terms that were accelerated as discussed above. Unrecognized compensation cost related to restricted shares that were unvested as of June 30, 2020 was $21.7 million, which the Company expects to recognize over a weighted average period of 1.9 years.
Stock Options
Stock options that have been granted under the LTIP expire ten years from the grant date and vest ratably over a three-year service period. The exercise price for an option granted under the LTIP is the closing market price of the Company’s Class A Common Stock on the grant date.
Compensation cost for stock options is based on the grant-date fair value of the award which is then recognized ratably over the vesting period of three years. The Company estimates the fair value using the Black-Scholes option-pricing model. Expected volatilities are based on the weighted average asset volatility of the Company and an identified set of comparable companies. Expected term is based on the simplified method and is estimated as the mid-point between the weighted average vesting term and the time to expiration as of the grant date. The Company uses U.S. Treasury bond rates in effect at the grant date for its risk-free interest rates.

20
CENTENNIAL RESOURCE DEVELOPMENT, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)


The following table summarizes the assumptions and related information used to determine the grant-date fair value of stock option awards for the periods presented:

Six Months Ended June 30,

2020

2019
Weighted average grant-date fair value per share
$
1.16


$
4.77

Expected term (in years)
6


6

Expected stock volatility
86
%

46
%
Dividend yield
—
%

—
%
Risk-free interest rate
1.0
%

2.4
%

The following table provides information about stock option awards outstanding during the six months ended June 30, 2020:
 
Options
 
Weighted Average Exercise Price
 
Weighted Average Remaining Term
(in years)
 
Aggregate Intrinsic Value
(in thousands)
Outstanding as of December 31, 2019
4,764,167

 
$
15.99

 
 
 
 
Granted
124,000

 
2.13

 
 
 
 
Exercised
—

 
—

 
 
 

Forfeited
(94,409
)
 
13.99

 
 
 
 
Expired
(2,086,164
)
 
16.34

 
 
 
 
Outstanding as of June 30, 2020
2,707,594

 
15.15

 
6.4
 
$
40

Exercisable as of June 30, 2020
2,136,070

 
15.95

 
5.9
 
$
—


The total fair value of stock options that vested during the six months ended June 30, 2020 and 2019 was $4.2 million and $4.1 million, respectively, and includes awards with vesting terms that were accelerated as discussed above. There were no stock options exercised during either the six months ended June 30, 2020 or 2019. As of June 30, 2020, there was $1.8 million of unrecognized compensation cost related to unvested stock options, which the Company expects to recognize on a pro-rata basis over a weighted-average period of 1.4 years.
Performance Stock Units
During the six months ended June 30, 2020 and 2019, there was no significant performance stock units activity. As of June 30, 2020, there was $3.7 million of unrecognized compensation cost related to performance stock units that were unvested, which the Company expects to recognize on a pro-rata basis over a weighted average period of 1.6 years.
Note 7—Derivative Instruments
The Company is exposed to certain risks relating to its ongoing business operations and may use derivative instruments to manage its exposure to commodity price risk from time to time.
Commodity Derivative Contracts
Historically, prices received for crude oil and natural gas production have been volatile because of supply and demand factors, worldwide political factors, general economic conditions and seasonal weather patterns. The Company may periodically use derivative instruments, such as swaps, costless collars and basis swaps, to mitigate its exposure to declines in commodity prices and to the corresponding negative impacts such declines can have on its cash flows from operations, returns on capital and other financial results. While the use of these instruments limits the downside risk of adverse price changes, their use may also limit future revenues from favorable price changes. The Company does not enter into derivative contracts for speculative or trading purposes.
Commodity Swap Contracts. The Company may use commodity derivative instruments known as fixed price swaps to realize a known price for a specific volume of production as well as basis swaps to hedge the difference between the index price and a local index price. All transactions are settled in cash with one party paying the other for the resulting difference in price multiplied by the contract volume.

21
CENTENNIAL RESOURCE DEVELOPMENT, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)


The following table summarizes the approximate volumes and average contract prices of swap contracts the Company had in place as of June 30, 2020:
 
Period
 
Volume (Bbls)
 
Volume
(Bbls/d)
 
Weighted Average Fixed Price ($/Bbl)(1)
Crude oil swaps
July 2020 - September 2020
 
2,300,000

 
25,000

 
$
26.83

 
October 2020 - December 2020
 
1,196,000

 
13,000

 
38.89

 
 
 
 
 
 
 
 

Period

Volume (Bbls)

Volume
(Bbls/d)

Weighted Average Differential ($/Bbl)(2)
Crude oil basis swaps
July 2020 - September 2020

1,472,000

 
16,000

 
$
0.52

 
October 2020 - December 2020
 
874,000

 
9,500

 
0.61


 
(1) 
These crude oil swap transactions are settled based on the NYMEX WTI price on each trading day within the specified monthly settlement period.
(2) 
These oil basis swap transactions are settled based on the difference between the arithmetic average of ARGUS MIDLAND WTI and ARGUS WTI CUSHING indices, during each applicable settlement period.

Period

Volume (MMBtu)

Volume (MMBtu/d)

Weighted Average Fixed Price ($/MMBtu)(1)
Natural gas swaps
July 2020 - September 2020

2,760,000


30,000


$
2.03

 
October 2020 - December 2020
 
2,150,000

 
23,370

 
2.40

 
January 2021 - March 2021
 
1,800,000

 
20,000

 
2.68

 








Period

Volume (MMBtu)

Volume (MMBtu/d)

Weighted Average Differential ($/MMBtu)(2)
Natural gas basis swaps
July 2020 - September 2020

2,760,000


30,000


$
(1.62
)
 
October 2020 - December 2020
 
930,000

 
10,109

 
(1.62
)
 
(1) 
These natural gas swap contracts are settled based on the NYMEX Henry Hub price on each trading day within the specified monthly settlement period.
(2) 
These natural gas basis swap contracts are settled based on the difference between the Inside FERC’s West Texas WAHA price and the NYMEX price of natural gas, during each applicable settlement period.
Derivative Instrument Reporting. The Company’s oil and natural gas derivative instruments have not been designated as hedges for accounting purposes. Therefore, all gains and losses are recognized in the Company’s Consolidated Statements of Operations. All derivative instruments are recorded at fair value in the Consolidated Balance Sheets, other than derivative instruments that meet the “normal purchase normal sale” exclusion, and any fair value gains and losses are recognized in current period earnings.
The following table presents the impact of the Company’s derivative instruments in its Consolidated Statements of Operations for the periods presented:
 
Three Months Ended June 30,
 
Six Months Ended June 30,
(in thousands)
2020
 
2019
 
2020
 
2019
Net gain (loss) on derivative instruments
$
(29,857
)
 
$
2,128

 
$
(38,362
)
 
$
(3,743
)


22
CENTENNIAL RESOURCE DEVELOPMENT, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)


Offsetting of Derivative Assets and Liabilities. The Company’s commodity derivatives are included in the accompanying Consolidated Balance Sheets as derivative assets and liabilities. The Company nets its financial derivative instrument fair value amounts executed with the same counterparty pursuant to ISDA master netting agreements, which provide for net settlement over the term of the contract and in the event of default or termination of the contract. The tables below summarizes the fair value amounts and the classification in the Consolidated Balance Sheets of the Company’s derivative contracts outstanding at the respective balance dates, as well as the gross recognized derivative assets, liabilities and offset amounts:
 
Balance Sheet Classification
 
Gross Fair Value Asset/Liability Amounts
 
Gross Amounts Offset(1)
 
Net Recognized Fair Value Assets/Liabilities
(in thousands)
 
 
June 30, 2020
Derivative Assets
 
 
 
 
 
 
 
Commodity contracts
Current assets - Derivative instruments
 
$
2,861

 
$
(2,861
)
 
$
—

Derivative Liabilities
 
 
 
 
 
 
 
Commodity contracts
Current liabilities - Derivative instruments
 
34,601

 
(2,861
)
 
31,740

 
 
 
 
 
 
 
 
 
 
 
December 31, 2019
Derivative Liabilities
 
 
 
 
 
 
 
Commodity contracts
Current liabilities - Derivative instruments
 
$
325

 
$
—

 
$
325

 
(1)
The Company has agreements in place with all of its counterparties that allow for the financial right of offset for derivative assets against derivative liabilities at settlement or in the event of a default under the agreements or contract termination.
Contingent Features in Financial Derivative Instruments. None of the Company’s derivative instruments contain credit-risk-related contingent features. Counterparties to the Company’s financial derivative contracts are high credit-quality financial institutions that are lenders under CRP’s credit agreement. The Company uses only credit agreement participants to hedge with, since these institutions are secured equally with the holders of any CRP bank debt, which eliminates the potential need to post collateral when Centennial is in a derivative liability position. As a result, the Company is not required to post letters of credit or corporate guarantees for its derivative counterparties in order to secure contract performance obligations.
In addition, the Company is exposed to credit risk associated with its derivative contracts from non-performance by its counterparties. The Company mitigates its exposure to any single counterparty by contracting with a number of financial institutions, each of which has a high credit rating and is a member under CRP’s credit facility as referenced above.

23
CENTENNIAL RESOURCE DEVELOPMENT, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)


Note 8—Fair Value Measurements
Recurring Fair Value Measurements
The Company follows ASC Topic 820, Fair Value Measurement and Disclosure, which establishes a three-level valuation hierarchy for disclosure of fair value measurements. The valuation hierarchy categorizes assets and liabilities measured at fair value into one of three different levels depending on the observability of the inputs employed in the measurement. The three levels are defined as follows:

•
Level 1:  Quoted Prices in Active Markets for Identical Assets – inputs to the valuation methodology are quoted prices (unadjusted) for identical assets or liabilities in active markets.
•
Level 2:  Significant Other Observable Inputs – inputs to the valuation methodology include quoted prices for similar assets and liabilities in active markets, and inputs that are observable for the asset or liability, either directly or indirectly, for substantially the full term of the financial instrument.
•
Level 3:  Significant Unobservable Inputs – inputs to the valuation methodology are unobservable and significant to the fair value measurement.

The following table presents, for each applicable level within the fair value hierarchy, the Company’s net derivative assets and liabilities, including both current and noncurrent portions, measured at fair value on a recurring basis:
(in thousands)
Level 1
 
Level 2
 
Level 3
June 30, 2020
 
 
 
 
 
Total assets
$
—

 
$
—

 
$
—

Total liabilities
—

 
31,740

 
—

December 31, 2019
 
 
 
 
 
Total assets
$
—

 
$
—

 
$
—

Total liabilities
—

 
325

 
—


Both financial and non-financial assets and liabilities are categorized within the above fair value hierarchy 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 in its entirety requires judgment and considers factors specific to the asset or liability. The following is a description of the valuation methodologies used by the Company as well as the general classification of such instruments pursuant to the above fair value hierarchy. There were no transfers between any of the fair value levels during any period presented.
Derivatives
The Company uses Level 2 inputs to measure the fair value of its oil and natural gas commodity derivatives. The Company uses industry-standard models that consider various assumptions including current market and contractual prices for the underlying instruments, implied market volatility, time value, nonperformance risk, as well as other relevant economic measures. Substantially all of these inputs are observable in the marketplace throughout the full term of the instrument and can be supported by observable data. The Company utilizes its counterparties’ valuations to assess the reasonableness of its own valuations. Refer to Note 7—Derivative Instruments for details of the gross and net derivatives assets, liabilities and offset amounts presented in the Consolidated Balance Sheets.
Nonrecurring Fair Value Measurements
The Company applies the provisions of the fair value measurement standard on a nonrecurring basis to its non-financial assets and liabilities, including proved oil and gas properties. These assets and liabilities are not measured at fair value on an ongoing basis but are subject to fair value adjustments in certain circumstances.
Impairment of Oil and Natural Gas Properties. The Company reviews its proved oil and natural gas properties for impairment whenever events and circumstances indicate that the fair value of these assets may be below their carrying value. The significant decrease in the forward price curves for crude oil and natural gas in March of 2020 resulted in a triggering event which required the Company to reassess its proved oil and natural gas properties for impairment as of March 31, 2020. An impairment loss is indicated if the sum of the expected undiscounted future net cash flows from oil and gas properties is less than the carrying amount of the assets. In this circumstance, the Company then recognizes impairment expense for the amount by which the carrying amount of proved properties exceeds their estimated fair value. The Company reviews its oil and natural gas properties on a field-by-field basis.

24
CENTENNIAL RESOURCE DEVELOPMENT, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)


The Company calculates the estimated fair values of its oil and natural gas properties using an income approach that is based on inputs that are not observable in the market and therefore represent Level 3 inputs. Significant inputs to the expected future net cash flows used for the impairment review and the related fair value measurement of oil and natural gas proved properties include estimates of: (i) reserves; (ii) future production decline rates; (iii) future operating and development costs; (iv) future commodity prices, including price differentials; and (v) a market participant-based weighted average cost of capital rate. These inputs require significant judgments and estimates by the Company’s management.
The impairment test performed by the Company indicated that a proved property impairment had occurred with respect to certain of its oil and gas fields, and therefore a non-cash impairment charge to reduce the carrying value of the impaired property to its fair value was recorded. Proved oil and natural gas properties with a previous carrying value of $771.4 million were partially written down to their fair value of $179.6 million, resulting in a non-cash impairment charge of $591.8 million being recorded in the first quarter of 2020. All of the Company’s proved oil and gas properties were included in the impairment assessment performed as of March 31, 2020. Two of the Company’s fields were subject to an impairment write-down as quantified above, but the remaining five fields were not impaired due to their undiscounted cash flows exceeding their carrying values by 30% to over 100%. There were no triggering event identified as of June 30, 2020 or 2019 and therefore the Company did not recognize any impairment write-downs with respect to its proved property for the three months ended June 30, 2020 and for the three and six months ended June 30, 2019. Impairment expense for proved properties is presented as part of Impairment and Abandonment Expense in the Consolidated Statements of Operations.
Asset Retirement Obligations. The initial measurement of ARO at fair value is calculated using discounted cash flow techniques and is based on internal estimates of future retirement costs associated with property, plant and equipment. Significant Level 3 inputs used in the calculation of ARO include the estimated future costs to plug and abandon oil and gas properties and reserve lives. Refer to Note 5—Asset Retirement Obligations for additional information on the Company’s ARO.
Senior Secured Notes. The Company’s Senior Secured Notes were measured and recorded at their fair value on the date of issuance equal to 83.44% of par. The fair value was determined utilizing the Black-Derman-Toy binomial lattice model, which is a one-factor binomial lattice model that determines the future evolution of the relevant yields. For each node on the lattice, it is determined whether it is preferable to redeem, or not, based on the yields. The model utilizes both a yield curve and a yield volatility as of the valuation date, both of which are estimated based on yields of comparable debt instruments and are inputs that are not observable for the Senior Secured Notes for the term of the debt instrument (a Level 3 classification in the fair value hierarchy). The fair value was measured by the model using the following inputs: (i) the treasury yield curve as of the valuation date, (ii) 12% credit spread, (iii) 45% yield volatility, and (iv) a corporate credit rating of B. The Company has not elected the fair value option, which would require remeasurement at fair value each period, to account for this debt instrument.
Other Financial Instruments
The carrying amounts of the Company’s cash, cash equivalents, accounts receivable, accounts payable, and accrued liabilities approximate their fair values because of the short-term maturities and/or liquid nature of these assets and liabilities.
The Company’s Senior Notes and borrowings under its credit agreement are accounted for at cost, and the cost basis of the Company’s Senior Secured Notes issued in the Debt Exchange was measured based on their fair value on the date of the exchange, as discussed above. The following table summarizes the carrying values, principal amounts and fair values of these instruments as of the dates indicated:
 
 
June 30, 2020
 
December 31, 2019
 
 
Carrying Value
 
Principal Amount
 
Fair Value
 
Carrying Value
 
Principal Amount
 
Fair value
Credit facility due 2023(1)
 
$
370,000

 
$
370,000

 
$
370,000

 
$
175,000

 
$
175,000

 
$
175,000

8.00% Senior Secured Notes due 2025(2)
 
102,109

 
127,073

 
108,012

 
—

 
—

 
—

5.375% Senior Notes due 2026(2)
 
284,485

 
289,448

 
144,724

 
392,623

 
400,000

 
394,480

6.875% Senior Notes due 2027(2)
 
349,449

 
356,351

 
178,176

 
489,766

 
500,000

 
520,000

 
(1)  
The carrying values of the amounts outstanding under CRP’s credit agreement approximate fair value because its variable interest rates are tied to current market rates and the applicable credit spreads represent current market rates for the credit risk profile of the Company.
(2) 
The carrying values include associated unamortized debt issuance costs and any debt discounts as reflected in the Consolidated Balance Sheets. The fair values are determined using quoted market prices for these debt securities, a Level 1 classification in the fair value hierarchy, and are based on the aggregate principal amount of the Senior Notes outstanding.

25
CENTENNIAL RESOURCE DEVELOPMENT, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)


Note 9—Earnings Per Share
Basic earnings per share (“EPS”) is calculated by dividing net income available to Class A Common Stock by the weighted average shares of Class A Common Stock outstanding during each period. Diluted EPS is calculated by dividing adjusted net income available to Class A Common Stock by the weighted average shares of diluted Class A Common Stock outstanding, which includes the effect of potentially dilutive securities. Potentially dilutive securities for the diluted EPS calculation consists of (i) unvested restricted stock and performance stock units, outstanding stock options, withholding amounts from employee stock purchase plan and warrants using the treasury stock method, and (ii) the Company’s Class C Common Stock outstanding prior to the Conversion using the “if-converted” method, which is net of tax.
The following table reflects the allocation of net income to common shareholders and EPS computations for the periods indicated based on a weighted average number of common shares outstanding for the period:

Three Months Ended June 30,
 
Six Months Ended June 30,
(in thousands, except per share data)
2020
 
2019

2020

2019
Net income (loss) attributable to Class A Common Stock
$
5,330


$
17,877


$
(542,653
)

$
9,765

Add: Income from conversion of Class C Common Stock
—


735


—


442

Adjusted net income (loss) attributable to Class A Common Stock
$
5,330

 
$
18,612

 
$
(542,653
)
 
$
10,207

 
 
 
 
 
 
 
 
Basic weighted average shares of Class A Common Stock outstanding
277,133

 
264,378

 
276,543

 
264,397

Add: Dilutive effects of potential common stock
75

 
14

 
—

 
15

Add: Dilutive effects of conversion of Class C Common Stock
—

 
12,003

 
—

 
12,003

Diluted weighted average shares of Class A Common Stock outstanding
277,208

 
276,395

 
276,543

 
276,415

 
 
 
 
 
 
 
 
Basic net earnings (loss) per share of Class A Common Stock
$
0.02

 
$
0.07

 
$
(1.96
)
 
$
0.04

Diluted net earnings (loss) per share of Class A Common Stock
$
0.02

 
$
0.07

 
$
(1.96
)
 
$
0.04


The Company recognized a net loss during the six months ended June 30, 2020. As a result, all potential common shares were anti-dilutive and were excluded from the calculation of diluted net earnings per share. The following table presents shares excluded from the diluted earnings per share calculation for the periods presented as their impact was anti-dilutive:
 
Three Months Ended June 30,
 
Six Months Ended June 30,
(in thousands)
2020
 
2019
 
2020
 
2019
Out-of-the-money stock options
4,696

 
4,667

 
4,756

 
4,612

Restricted stock
5,066

 
1,758

 
5,125

 
1,629

Employee Stock Purchase Plan
—

 
—

 
139

 
—

Weighted average shares of Class C Common Stock
11

 
—

 
523

 
—

Warrants
8,000

 
8,000

 
8,000

 
8,000



26
CENTENNIAL RESOURCE DEVELOPMENT, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)


Note 10—Transactions with Related Parties
Riverstone and its affiliates (“Riverstone”) beneficially own a more than 10% equity interest in the Company and are therefore considered related parties. The Company has a marketing agreement with Lucid Energy Delaware, LLC (“Lucid”), an affiliate of Riverstone. The Company believes that the terms of the marketing agreement with Lucid are no less favorable to either party than those held with unaffiliated parties. The following table summarizes the revenues recognized and the associated processing fees incurred from this marketing agreement as presented in the Consolidated Statements of Operations for the periods indicated as well as the related net receivables outstanding as of the balance sheet dates:

Three Months Ended June 30,

Six Months Ended June 30,
(in thousands)
2020

2019

2020

2019
Oil and gas sales
$
574


$
1,189


$
1,662


$
1,796

Gathering, processing and transportation expenses
1,109

 
609

 
2,062

 
926

(in thousands)
June 30, 2020
 
December 31, 2019
Receivable from (payable to) Lucid(1)
$
(367
)
 
$
91

 
(1) Represents amounts due from or payable to Lucid and are presented net of unpaid processing fees as of the indicated period end date.
Senior Secured Notes
During 2020, Riverstone acquired an aggregate of $100.7 million and $111.9 million of the Company’s 2026 Senior Notes and 2027 Senior Notes, respectively, in open market purchases. Subsequently, on May 22, 2020, Riverstone participated in the Company’s Debt Exchange, discussed in Note 4—Long-Term Debt, and exchanged all of its Senior Unsecured Notes for $106.3 million of the Company’s Senior Secured Notes. Riverstone’s participation in the Debt Exchange represented $106.3 million (or 74%) of the total extinguishment gain recognized in the consolidated statements of operations.
Note 11—Commitments and Contingencies
Commitments
The Company routinely enters into, extends or amends operating agreements in the ordinary course of business. During the six months ended June 30, 2020, the Company amended one of its firm crude oil sales agreements, which moved the start date of its physical delivery commitments of 30,000 Bbls/d from 2020 to January 1, 2021, and affirmed May 31, 2025 as the end of the initial term of the agreement. There has been no other material, non-routine changes in commitments during the six months ended June 30, 2020. Please refer to Note 13—Commitments and Contingencies included in Part II, Item 8 in the Company’s 2019 Annual Report.
Contingencies
The Company may at times be subject to various commercial or regulatory claims, litigation or other legal proceedings that arise in the ordinary course of business. While the outcome of these lawsuits and claims cannot be predicted with certainty, management believes it is remote that the impact of such matters that are reasonably possible to occur will have a material adverse effect on the Company’s financial position, results of operations, or cash flows. Management is unaware of any pending litigation brought against the Company requiring a contingent liability to be recognized as of the date of these consolidated financial statements.
Note 12—Revenues
Revenue from Contracts with Customers
Crude oil, natural gas and NGL sales are recognized at the point that control of the product is transferred to the customer and collectability is reasonably assured. Virtually all of the Company’s contract pricing provisions are tied to a market index, with certain adjustments based on, among other factors, transportation costs to an active spot market and quality differentials. As a result, the Company’s realized prices of oil, natural gas, and NGLs fluctuate to remain competitive with other available oil, natural gas, and NGLs supplies both globally (in the case of crude oil) and locally.

27
CENTENNIAL RESOURCE DEVELOPMENT, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)


Oil and gas revenues presented within the Consolidated Statements of Operations relate to the sale of oil, natural gas and NGLs as shown below:
 
Three Months Ended June 30,
 
Six Months Ended June 30,
 
2020
 
2019
 
2020

2019
Operating revenues (in thousands):
 
 
 
 
 
 
 
Oil sales
$
73,100

 
$
214,305

 
$
243,605

 
$
389,859

Natural gas sales
8,787

 
8,088

 
17,145

 
20,585

NGL sales
8,622

 
21,846

 
22,528

 
48,364

Oil and gas sales
$
90,509

 
$
244,239

 
$
283,278

 
$
458,808


Oil sales
The Company’s crude oil sales contracts are generally structured whereby oil is delivered to the purchaser at a contractually agreed-upon delivery point at which the purchaser takes title of the product. This delivery point is usually at the wellhead or at the inlet of a transportation pipeline. Revenue is recognized when control transfers to the purchaser at the delivery point based on the net price received from the purchaser. Any downstream transportation costs incurred by crude purchasers are reflected as a net reduction to oil sales revenues.
Natural gas and NGL sales
Under the Company’s natural gas processing contracts, liquids rich natural gas is delivered to a midstream processing entity at the inlet of the gas plant processing system. The midstream processing entity gathers and processes the raw gas and then remits proceeds to Centennial for the resulting sales of NGLs, while the Company generally elects to take its residue gas product “in-kind” at the plant tailgate. For these contracts, the Company evaluates when control is transferred and revenue should be recognized. Where the Company has concluded that control transfers at the tailgate of the processing facility, fees incurred prior to transfer of control are presented as gathering, processing and transportation expenses (“GP&T”) within the Consolidated Statements of Operations. Any transportation and fractionation costs incurred subsequent to the point of transfer of control are reflected as a net reduction to natural gas and NGL sales revenues presented in the table above.
Performance obligations
For all commodity products, the Company records revenue in the month production is delivered to the purchaser. Settlement statements for natural gas and NGL sales may not be received for 30 to 90 days after the date production volumes are delivered and for crude oil, generally within 30 days after delivery has occurred. However, payment is unconditional once the performance obligations have been satisfied. At such time, the volumes delivered and sales prices can be reasonably estimated and amounts due from customers are accrued in Accounts receivable, net in the Consolidated Balance Sheets. As of June 30, 2020 and December 31, 2019, such receivable balances were $41.5 million and $76.6 million, respectively.
The Company records any differences between its estimates and the actual amounts received for product sales in the month that payment is received from the purchaser. Historically, any identified differences between revenue estimates and actual revenue received have not been significant. For the six months ended June 30, 2020 and 2019, revenue recognized in the reporting period related to performance obligations satisfied in prior reporting periods were not material.
Transaction price allocated to remaining performance obligations
For the Company’s product sales that have a contract term greater than one year, the Company has utilized the practical expedient in ASC Topic 606, Revenue from contracts with Customers, which states the Company is not required to disclose the transaction price allocated to the remaining performance obligations if the variable consideration is allocated entirely to a wholly unsatisfied performance obligation. Under these sales contracts, monthly sales of a product generally represent a separate performance obligation. Therefore, future commodity volumes to be delivered and sold are wholly unsatisfied, and disclosure of the transaction price allocated to such unsatisfied performance obligations is not required.
Note 13—Leases
At contract inception, the Company determines whether or not an arrangement contains a lease. However, in connection with the implementation of ASC Topic 842, Leases (“ASC 842”), this assessment was made as of the adoption date of ASC 842. Upon determination of a lease, a lease right-of-use (“ROU”) asset and related liability are recorded based on the present value of the future lease payments over the lease term. ROU assets represent the Company’s right to use an underlying asset for the lease term, and lease liabilities represent the obligation to make future lease payments arising from the lease.

28
CENTENNIAL RESOURCE DEVELOPMENT, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)


The Company has operating leases for drilling rig contracts, office rental agreements, and other wellhead equipment. As of June 30, 2020, these leases have remaining lease terms ranging from two months to two years, some of which include options to extend the lease term for up to five years, and some of which include options to early terminate. These options are considered in determining the lease term and are included in the present value of future payments that are recorded for leases when the Company is reasonably certain to exercise the option. Leases with an initial term of one year or less are not recorded in the Consolidated Balance Sheets. Additionally, none of the Company’s lease agreements contain any material residual value guarantees or material restrictive covenants.
The present value of future lease payments is determined at the lease commencement date based upon the Company’s incremental borrowing rate. The incremental borrowing rate is calculated using a risk-free interest rate adjusted for the Company’s specific risk and the specific lease term. The table below summarizes the Company’s weighted-average discount rate and weighted-average remaining lease term as of the period presented.
 
 
As of June 30, 2020
Weighted-average discount rate
 
4.76
%
Weighted-average remaining lease term (years)
 
1.45


The Company’s drilling rig contracts, office rental agreements, and wellhead equipment agreements contain both lease and non-lease components, which are combined and accounted for as a single lease component.
Variable lease payments are recognized in the period in which they are incurred and include operating expenses related to the office rental agreements and expenses incurred on the drilling rig contracts in excess of the contractual rate. Expenses related to short-term leases are recognized on a straight-line basis over the lease term. The following table presents the various components of the Company’s lease expenses for the periods presented.
 
Three Months Ended June 30,
 
Six Months Ended June 30,
(in thousands)
2020
 
2019
 
2020
 
2019
Lease costs(1)
 
 
 
 
 
 
 
Operating lease cost
$
1,595

 
$
10,806

 
$
6,271

 
$
21,393

Variable lease cost
3,669

 
703

 
5,021

 
1,504

Short-term lease cost(2)
12,217

 
16,684

 
31,827

 
28,908

Total lease cost
$
17,481

 
$
28,193

 
$
43,119

 
$
51,805

 
(1)  
The majority of the Company’s operating leases relate to the operations, drilling or completion of the Company’s wells. Therefore, the lease costs presented in the above table represent the total gross costs the Company incurs, which are not comparable to the Company’s net costs recorded to the Consolidated Statements of Operations, Consolidated Statements of Cash Flows or capitalized in the Consolidated Balance Sheets, as amounts therein are reflected net of amounts billed to the Company’s working interest partners.
(2)  
Includes drilling rig lease costs of $4.6 million and $15.8 million for the three and six months ended June 30, 2020, which may not necessarily be recurring in these amounts in the near-term based on the Company’s reduction in its drilling plan.

29
CENTENNIAL RESOURCE DEVELOPMENT, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)


Maturities of the Company’s long-term operating lease liabilities by fiscal year as of June 30, 2020 are as follows:
(in thousands)
Total(2)
2020(1)
$
2,211

2021
3,178

2022
425

Total lease payments
5,814

  Less: imputed interest
(440
)
Present value of lease liabilities (3)
$
5,374

 
(1)
Excludes payments made during the six months ended June 30, 2020.
(2) 
Total lease payments exclude variable lease payments which can be charged under the terms of the lease agreements.
(3)
Of the total present value of lease liabilities, $3.6 million was recorded to current Operating lease liabilities and $1.8 million was recorded in noncurrent Operating lease liabilities in the Consolidated Balance Sheets as of June 30, 2020.
Note 14—Subsequent Events
In July 2020, the Company redeemed its one outstanding share of Series A Preferred Stock, par value $0.0001 per share (the “Series A Preferred Stock”), held by NGP X US Holdings, L.P. (“NGP”), a former indirect equity owner of CRP. The Series A Preferred Stock became redeemable by the Company as NGP ceased to own at least 5,000,000 shares of Class A Common Stock.

30

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operation
The following discussion and analysis of our financial condition and results of operation should be read in conjunction with the accompanying consolidated financial statements and related notes. The following discussion and analysis contains forward-looking statements that reflect our future plans, estimates, beliefs and expected performance. The forward-looking statements are dependent upon events, risks and uncertainties that may be outside our control. Our actual results could differ materially from those discussed in these forward-looking statements. Factors that could cause or contribute to such differences include, but are not limited to, market prices for oil, natural gas and NGLs, production volumes, estimates of proved reserves, capital expenditures, economic and competitive conditions, regulatory changes, continued and future impacts of Coronavirus Disease 2019 (“COVID-19”) and other uncertainties, as well as those factors discussed above in “Cautionary Statement Regarding Forward-Looking Statements” and under the heading “Item 1A. Risk Factors” in this Quarterly Report and our 2019 Annual Report, all of which are difficult to predict. In light of these risks, uncertainties and assumptions, the forward-looking events discussed may not occur. We do not undertake any obligation to publicly update any forward-looking statements except as otherwise required by applicable law.
Overview
Centennial Resource Development, Inc. (“Centennial,” “we,” “us,” or “our”) is an independent oil and natural gas company focused on the development of unconventional oil and associated liquids-rich natural gas reserves in the Permian Basin. Our assets are primarily in the Delaware Basin, a sub-basin of the Permian Basin. Our capital programs are specifically focused on projects that we believe provide the highest return on capital. Unless otherwise specified or the context otherwise requires, all references in these discussions to “Centennial,” “we,” “us,” or “our” are to Centennial Resource Development, Inc. and its consolidated subsidiary, Centennial Resource Production, LLC (“CRP”).
Market Conditions
The recent worldwide outbreak of COVID-19, the uncertainty regarding the impact of COVID-19 and various governmental actions taken to mitigate the impact of COVID-19, have resulted in an unprecedented decline in demand for oil and natural gas. At the same time, the decision by Saudi Arabia in March 2020 to drastically reduce export prices and increase oil production followed by curtailment agreements among OPEC and other countries such as Russia further increased uncertainty and volatility around global oil supply-demand dynamics. As a result, there has been a significant decline in commodity prices starting in the first quarter of 2020. However, during the second quarter of 2020, OPEC and other oil producing countries agreed to reduce their crude oil production and then extend such production cuts through at least August of 2020, while U.S. producers substantially reduced or suspended drilling activity, and in most cases curtailed production, due to low oil prices and poor economics. These actions have aided in a partial recovery of global commodity prices. Specifically, WTI spot prices for crude oil fell to a low of negative ($37.63) on April 20, 2020 (due to depressed demand and insufficient storage capacity, particularly at the WTI physical settlement location in Cushing, Oklahoma) and have since partially recovered to a high of $40.46 on June 22, 2020.
The oil and natural gas industry is cyclical, and it is likely that commodity prices, as well as commodity price differentials, will continue to be volatile and fluctuate due to global supply and demand, inventory levels, the continued effects from COVID-19, geopolitical events, weather conditions and other factors. The following table highlights the quarterly average NYMEX price trends for crude oil and natural gas since the first quarter of 2018:
 
2018
 
2019
 
2020
 
Q1
 
Q2
 
Q3
 
Q4
 
Q1
 
Q2
 
Q3
 
Q4
 
Q1
 
Q2
Crude oil (per Bbl)
$
62.91

 
$
68.07

 
$
69.50

 
$
58.81

 
$
54.90

 
$
59.81

 
$
56.45

 
$
56.94

 
$
46.19

 
$
28.00

Natural gas (per MMBtu)
$
3.08

 
$
2.85

 
$
2.93

 
$
3.77

 
$
2.88

 
$
2.51

 
$
2.33

 
$
2.34

 
$
1.88

 
$
1.65

A sustained drop in oil, natural gas and NGL prices, such as those we have experienced in the first half of 2020, will not only decrease our revenues on a per unit basis but can also reduce the amount of oil, natural gas and NGLs that we can produce economically and therefore potentially lower our oil, natural gas and NGL reserve quantities.
Lower commodity prices (including realized differentials) and lower futures curves for oil and gas prices, can also result in further impairments of our proved oil and natural gas properties or undeveloped acreage (such as the impairments discussed below under “Results of Operations”) and may materially and adversely affect our future business, financial condition, results of operations, operating cash flows, liquidity and/or ability to finance planned capital expenditures. Lower realized prices may also reduce the borrowing base under CRP’s credit agreement (such as the reduction discussed below under “Financing Highlights”), which is determined at the discretion of the lenders and is based on the collateral value of our proved reserves that have been mortgaged to the lenders. Upon a redetermination, if any borrowings in excess of the revised borrowing capacity were outstanding, we could be forced to immediately repay a portion of the debt outstanding under the credit agreement. Additionally,

31

the lower price environment and its impact to our operations could impact our ability to comply with the covenants under our credit agreement and senior notes.
COVID-19 Outbreak
The COVID-19 outbreak and its development into a pandemic in March 2020 have required that we take precautionary measures intended to help minimize the risk to our business, employees, customers, contractors, suppliers and the communities in which we operate. Our operational employees have been and are currently able to work on site, while the vast majority of our non-operational employees worked remotely during the months of March and April but have started to report back to our offices on a limited basis starting in mid-May. We have taken various precautionary measures with respect to our operational employees and employees who return to our offices such as (i) requiring them to verify they have not experienced any symptoms consistent with COVID-19, or been in close contact with someone showing such symptoms, before reporting to the work site or office, (ii) self-quarantining any employees who have shown signs of COVID-19 (regardless of whether such employee has been confirmed to be infected), and (iii) imposing social distancing requirements on work sites and at our offices, that are in accordance with the guidelines released by the Center for Disease Control as well as local and state authorities. We have not experienced any operational disruptions (including disruptions from our suppliers and service providers) as a result of the COVID-19 outbreak.
2020 Highlights and Future Considerations
The changes in the macro environment and related volatility in commodity prices that occurred during the first half of 2020 discussed above have significantly impacted our results of operations for the three and six months ended June 30, 2020, and we believe that our future operating results and near-term financial condition will continue to be impacted, until such time that oil supply and demand dynamics stabilize. Further, our results of operations for the three and six months ended June 30, 2020 discussed within this Quarterly Report will likely not be indicative of our operating results for the remainder of 2020 due to the timing of operational changes and continued volatility of commodity prices.
Operational Highlights
We operated a five-rig drilling program during the majority of the first quarter of 2020, which enabled us to complete and bring online 26 gross operated wells with an average effective lateral length of approximately 7,200 feet during the first half of 2020.
Due to the decline in crude oil prices and ongoing uncertainty regarding the oil supply-demand macro environment, we suspended all drilling and completion activities in order to preserve capital. Specifically, we reduced our operated drilling rig program to zero rigs starting in April of 2020 and continued with no rigs in operation for the remainder of the second quarter. In addition, given the weakness in realized oil prices, we voluntarily curtailed or shut-in a portion of our production volumes. Specifically, we curtailed approximately 20% of our production during the month of May, but were able to bring the majority of our production back online in June, with minimal incremental cost as crude oil prices recovered. Additionally, the Company filled its on-site tank batteries with crude oil during May in order to minimize the amount of shut-in volumes, ultimately selling these barrels in June at higher prices. The potential for any future curtailment decisions will continue to be evaluated and made on a month-to-month basis subject to market conditions, storage or transportation constraints, and contractual obligations. As substantially all of our revenues are generated by the production and sale of hydrocarbons, the curtailment or shut-in of our production could adversely affect our business, financial condition, results of operations, liquidity, and ability to finance planned capital expenditures.
Financing Highlights
On May 22, 2020, we completed an opportunistic private exchange of our debt pursuant to which $110.6 million aggregate principal amount of CRP’s 5.375% senior notes due 2026 (the “2026 Senior Notes”) and $143.7 million aggregate principal amount of CRP’s 6.875% senior notes due 2027 (the “2027 Senior Notes” and, together with the 2026 Senior Notes, the “Senior Unsecured Notes”) were validly tendered and exchanged by certain eligible bondholders for consideration consisting of $127.1 million aggregate principal amount (the “Debt Exchange”) of newly issued 8.00% second lien senior secured notes due 2025 (the “Senior Secured Notes”). This transaction resulted in the removal of $127.1 million in principal amount of Senior Unsecured Notes from the long-term debt balance in our Consolidated Balance Sheets.
On May 1, 2020, we entered into amendments to CRP’s amended and restated credit agreement (the “2020 Amendments”) with the lenders to our existing credit agreement. Pursuant to the 2020 Amendments, the borrowing base and level of elected commitments were reduced to $700.0 million. The 2020 Amendments that the lenders approved permitted the issuance of the Senior Secured Notes in connection with the Debt Exchange, and they implemented an availability blocker of $31.8 million equal to 25% of the newly issued and outstanding Senior Secured Notes. Among other things, the Amendments also suspended the total funded debt to EBITDAX ratio (as specified in the existing credit agreement) through year-end 2021 and introduced a new financial covenant testing the ratio of first lien debt to EBITDAX.

32

Results of Operations
Three Months Ended June 30, 2020 Compared to Three Months Ended June 30, 2019
The following table provides the components of our net revenues and net production (net of all royalties, overriding royalties and production due to others) for the periods indicated, as well as each period’s average prices and average daily production volumes:
 
Three Months Ended June 30,
 
Increase/(Decrease)
 
2020
 
2019

$

%
Net revenues (in thousands):
 
 
 




Oil sales
$
73,100


$
214,305


$
(141,205
)

(66
)%
Natural gas sales
8,787


8,088


699


9
 %
NGL sales
8,622


21,846


(13,224
)

(61
)%
Oil and gas sales
$
90,509


$
244,239


$
(153,730
)

(63
)%
 
 
 
 





Average sales prices:
 
 
 





Oil (per Bbl)
$
21.47


$
54.63


$
(33.16
)

(61
)%
Effect of derivative settlements on average price (per Bbl)
(1.60
)

(0.18
)

(1.42
)

(789
)%
Oil net of hedging (per Bbl)
$
19.87


$
54.45


$
(34.58
)

(64
)%
 
 
 
 





Average NYMEX price for oil (per Bbl)
$
28.00


$
59.81


$
(31.81
)

(53
)%
Oil differential from NYMEX
(6.53
)

(5.18
)
 
(1.35
)
 
(26
)%
 
 
 
 





Natural gas (per Mcf)
$
0.87


$
0.81


$
0.06


7
 %
Effect of derivative settlements on average price (per Mcf)
(0.14
)

0.71


(0.85
)

(120
)%
Natural gas net of hedging (per Mcf)
$
0.73


$
1.52


$
(0.79
)

(52
)%
 
 
 
 





Average NYMEX price for natural gas (per Mcf)
$
1.65


$
2.51


$
(0.86
)

(34
)%
Natural gas differential from NYMEX
(0.78
)

(1.70
)
 
0.92

 
54
 %
 
 
 
 





NGL (per Bbl)
$
7.72


$
16.24


$
(8.52
)

(52
)%
 
 
 
 





Net production:
 
 
 





Oil (MBbls)
3,404


3,922


(518
)

(13
)%
Natural gas (MMcf)
10,140


9,954


186


2
 %
NGL (MBbls)
1,116


1,346


(230
)

(17
)%
Total (MBoe)(1)
6,210


6,927


(717
)

(10
)%
 
 
 
 





Average daily net production:
 
 
 





Oil (Bbls/d)
37,411


43,105


(5,694
)

(13
)%
Natural gas (Mcf/d)
111,419


109,392


2,027


2
 %
NGL (Bbls/d)
12,264


14,785


(2,521
)

(17
)%
Total (Boe/d)(1)
68,245


76,122


(7,877
)

(10
)%
 
(1) 
Calculated by converting natural gas to oil equivalent barrels at a ratio of six Mcf of natural gas to one Boe.
Oil, Natural Gas and NGL Sales Revenues. Total net revenues for the three months ended June 30, 2020 were $153.7 million (or 63%) lower than total net revenues for the three months ended June 30, 2019. Revenues are a function of oil, natural gas and NGL volumes sold and average commodity prices realized.

33

Average realized sales prices for oil and NGLs decreased in the second quarter of 2020 compared to the same 2019 period. The average price for oil before the effects of hedging decreased 61% and the average price for NGLs decreased 52% between periods. The 61% decrease in the average realized oil price was the result of lower NYMEX crude prices between periods (average NYMEX prices decreased 53%) and wider oil differentials (an increase of $1.35 per Bbl). The 52% decrease in average realized NGL prices between periods was primarily attributable to lower Mont Belvieu spot prices for plant products in the second quarter of 2020 as compared to the second quarter of 2019. Conversely, the average price for natural gas before the effects of hedging increased 7% in the second quarter 2020 compared to the same 2019 period. This increase was mainly due to improved gas differentials (a decrease of $0.92 per Mcf), which was largely offset by lower average NYMEX gas prices between periods (average NYMEX prices decreased $0.86 per Mcf). The improvement in gas differentials is the result of higher natural gas prices realized in West Texas as several producers shut-in wells and curtailed production in the Permian Basin during the second quarter and as new pipelines have been placed into service. These pipelines have provided relief from gas pipeline takeaway capacity constraints experienced in 2019. The market prices for oil, natural gas and NGLs were significantly impacted by lower demand globally for oil and gas as a result of COVID-19 as well as commodity supply disruptions, both of which combined resulted in significant price declines starting in March 2020, as discussed in the market conditions section above.
Net production volumes for oil and NGLs decreased 13% and 17%, respectively, while natural gas increased 2% between periods. The crude oil production volume decrease was the result of (i) the temporary suspension of our drilling and completion activity in the second quarter of 2020, which resulted in only four new wells completed and brought online during the period as compared to 20 wells completed and brought online in the second quarter of 2019; (ii) the curtailment of a portion of our production during the month of May in the second quarter of 2020; and (iii) normal field production declines across our existing wells. These production decreases were partially offset by 70 gross operated wells placed on production in the Delaware Basin since the second quarter of 2019, which added 1,604 MBbls of net oil production to the three months ended June 30, 2020. Natural gas and NGLs are produced concurrently with our crude oil volumes, typically resulting in a high correlation between fluctuations in oil quantities sold and natural gas and NGL quantities sold. However, during the second quarter of 2020, the main processor of our raw gas operated in partial ethane-rejection for two-thirds of the quarter, as compared to operating in full ethane-recovery during the entire 2019 period. As a result, we sold an increased amount of natural gas from our wet gas stream and recovered fewer NGLs during the 2020 period, resulting in an increase (2%) in natural gas volumes and a decrease (17%) in NGL volumes between periods.
Operating Expenses. The following table sets forth selected operating expense data for the periods indicated:
 
Three Months Ended June 30,
 
Increase/(Decrease)
 
2020
 
2019
 
$

%
Operating costs (in thousands):
 
 
 
 



Lease operating expenses
$
25,839

 
$
34,885

 
$
(9,046
)

(26
)%
Severance and ad valorem taxes
5,696

 
17,186

 
(11,490
)

(67
)%
Gathering, processing and transportation expenses
17,284

 
16,243

 
1,041


6
 %
Operating costs per Boe:
 
 
 
 




Lease operating expenses
$
4.16

 
$
5.04

 
$
(0.88
)

(17
)%
Severance and ad valorem taxes
0.92

 
2.48

 
(1.56
)

(63
)%
Gathering, processing and transportation expenses
2.78

 
2.34

 
0.44


19
 %
Lease Operating Expenses. Lease operating expenses (“LOE”) for the three months ended June 30, 2020 decreased $9.0 million compared to the three months ended June 30, 2019. Lower LOE for the second quarter of 2020 was primarily related to a $7.6 million decrease in workover expense between periods as a result of lower workover activity and a $1.4 million decrease in variable and semi-variable operating costs as a result of lower production activity between periods.
LOE on a per Boe basis decreased when comparing the second quarter of 2020 to the same 2019 period. LOE per Boe was $4.16 for the second quarter of 2020, which represents a decrease of $0.88 per Boe (or 17%) from the second quarter of 2019. This decrease in rate was mainly due to the lower level of workover activity, discussed above, as well as cost reduction initiatives we have undertaken such as lowering contract labor costs and decreasing monthly equipment rentals, which were achieved by moving multiple wells off generators to more efficient electrical line-power. These decreases were partially offset by per BOE cost increases associated with fixed and semi-variable costs that don’t decrease at the same rate as declines in production such as (i) monthly rental fees for compressors and electric submersible pumps (“ESPs”), and (ii) wellhead chemical costs.

34

Severance and Ad Valorem Taxes. Severance and ad valorem taxes for the three months ended June 30, 2020 decreased $11.5 million compared to the three months ended June 30, 2019. Severance taxes are primarily based on the market value of production at the wellhead, while ad valorem taxes are generally based on the assessed taxable value of proved developed oil and natural gas reserves and vary across the different counties in which we operate. Severance and ad valorem taxes as a percentage of total net revenues decreased to 6.3% for the second quarter of 2020 as compared to 7.0% for the same 2019 period. This decrease in rate between periods was mainly due to (i) lower severance paid on the taxable values of natural gas and (ii) $0.3 million in tax credits received on wells designated “high cost gas” by the state of Texas.
Gathering, Processing and Transportation Expenses. Gathering, processing and transportation expenses (“GP&T”) for the three months ended June 30, 2020 increased $1.0 million as compared to the three months ended June 30, 2019 primarily due to a $2.4 million decrease in reimbursements (net of related fees) received from third parties for their usage of our available firm transport (“FT”) capacity. This was partially offset by a $1.3 million decrease in plant processing, transportation and gathering fees incurred between periods, which cost reductions were associated with lower NGL and oil production volumes between periods.
On a per Boe basis, GP&T increased from $2.34 for the second quarter of 2019 to $2.78 per Boe for the second quarter of 2020. On a natural gas and NGL volumes basis (i.e. excluding crude oil barrels) the Boe rate likewise increased between periods to $6.16 from $5.41 for the three months ended June 30, 2020 and 2019, respectively. These rate increases were mainly attributable to the decrease in FT reimbursements (net of related fees) received from third parties as discussed above.
Depreciation, Depletion and Amortization. The following table summarizes our depreciation, depletion and amortization (“DD&A”) for the periods indicated: 

Three Months Ended June 30,
(in thousands, except per Boe data)
2020

2019
Depreciation, depletion and amortization
$
93,020


$
112,114

Depreciation, depletion and amortization per Boe
$
14.98


$
16.18

Our DD&A rate can fluctuate as a result of finding and development costs incurred, acquisitions, impairments, as well as changes in proved developed and proved undeveloped reserves. For the three months ended June 30, 2020, DD&A expense amounted to $93.0 million, a decrease of $19.1 million over the same 2019 period. The primary factor contributing to lower DD&A expense in 2020 was the decrease in our overall production volumes between periods, which decreased DD&A expense by $11.5 million during the first half of 2020, while lower DD&A rates between periods lowered DD&A expense by $7.6 million.
DD&A per Boe was $14.98 for the second quarter of 2020 compared to $16.18 for the same period in 2019. The decrease in the DD&A rate was primarily due to the proved property impairment recognized in the first quarter of 2020, which lowered the carrying value of our depletion base by $591.8 million. The effect of this impairment, however, was partially offset by downward revisions in our proved reserves during the second quarter, mainly due to lower SEC pricing and a higher level of infrastructure costs incurred in the trailing twelve months, which have no associated proved reserve adds.
Impairment and Abandonment Expense. During the three months ended June 30, 2020, $19.4 million of impairment and abandonment expense was incurred related to the amortization of leasehold expiration costs associated with individually insignificant unproved properties.
During the three months ended June 30, 2019, $4.4 million of abandonment expense was incurred related to undeveloped leasehold acreage that expired after efforts to extend, sell or trade these leases were unsuccessful.
Exploration Expense. The following table summarizes our exploration expense for the periods indicated:  

Three Months Ended June 30,
(in thousands)
2020

2019
Geological and geophysical costs
$
1,081


$
3,179

Rig termination fees
1,547

 
—

Severance payments
722


—

Stock-based compensation
457


682

Other expenses
244

 
—

Exploration expense
$
4,051


$
3,861


35

Exploration expense was $4.1 million for the three months ended June 30, 2020 compared to $3.9 million for the three months ended June 30, 2019. Exploration expense mainly consists of topographical studies, geographical and geophysical (“G&G”) projects, and salaries and expenses of G&G personnel and includes other operating costs. The period over period increase was primarily related to the $1.5 million in rig termination fees incurred in the second quarter of 2020 as a result of reducing our operated drilling activity in April of 2020 and $0.7 million in nonrecurring severance payments to G&G personnel, resulting from our workforce reduction that was announced in the second quarter of 2020 (as further described below under General and Administrative Expenses). These increases were partially offset by $1.5 million in higher costs incurred on G&G projects and seismic studies in the 2019 period and $0.6 million in lower ongoing G&G personnel costs in the 2020 period associated with the workforce reduction referred to above.
General and Administrative Expenses. The following table summarizes our general and administrative (“G&A”) expenses for the periods indicated:  
 
Three Months Ended June 30,
(in thousands)
2020
 
2019
Cash general and administrative expenses
$
10,840


$
12,359

Stock-based compensation
4,270

 
6,076

Severance payments
2,884

 
—

General and administrative expenses
$
17,994

 
$
18,435

G&A expenses for the three months ended June 30, 2020 were $18.0 million compared to $18.4 million for the three months ended June 30, 2019. The lower G&A expenses incurred in the second quarter of 2020 was primarily the result of a reduction to our workforce and reduced salaries for the employees that remained, effective on May 1, 2020. These two factors combined resulted in (i) a $2.0 million decrease in employee payroll costs between periods, and (ii) a $1.8 million decrease in stock compensation expense, primarily related to reduced values of share awards modified and credits for shares forfeited, both in the workforce reduction (refer to Note 6—Stock-Based Compensation for additional information regarding the stock modification). These decreases were partially offset by nonrecurring charges incurred during the three months ended June 30, 2020 related to (i) $2.9 million in severance payments to G&A employees included in the workforce reduction, and (ii) $0.5 million of transaction costs that were expensed when the water disposal asset sale was terminated, which is included in cash G&A (see Note 2—Property Divestiture for additional information).
Other Income and Expenses. 
Interest Expense. The following table summarizes our interest expense for the periods indicated:
 
Three Months Ended June 30,
(in thousands)
2020
 
2019
Credit facility
$
3,159

 
$
879

8.00% Senior Secured Notes due 2025
1,129

 
—

5.375% Senior Unsecured Notes due 2026
4,732

 
5,375

6.875% Senior Unsecured Notes due 2027
7,524

 
8,594

Amortization of debt issuance costs and discount
1,535

 
775

Interest capitalized
(708
)
 
(1,186
)
Total
$
17,371

 
$
14,437

Interest expense was $2.9 million higher for the three months ended June 30, 2020 as compared to the three months ended June 30, 2019 primarily due to $2.3 million in increased interest expense incurred on our credit facility due to increased borrowings outstanding under the facility and $0.8 million in higher amortization related to debt issuance costs and debt discount recognized in connection with the Debt Exchange.
Our weighted average borrowings outstanding under our credit facility were $344.7 million versus $13.2 million for the three months ended June 30, 2020 and 2019, respectively. Our credit facility’s weighted average effective interest rate (which is a LIBOR-based rate) was 3.1% and 4.0% for the three months ended June 30, 2020 and 2019, respectively, as a result of lower LIBOR in the second quarter of 2020 versus the prior year quarter.

36

Gain on exchange of debt. A gain of $143.4 million was recognized for the three months ended June 30, 2020 related to our opportunistic Debt Exchange that was executed in the second quarter of 2020. This gain was determined based on the difference between the carrying value of the Senior Unsecured Notes extinguished less the fair value at the date of issuance of our newly issued Senior Secured Notes. Refer to Note 4—Long-Term Debt for additional information regarding the gain on exchange of debt.
Net Gain (Loss) on Derivative Instruments. Net gains and losses are a function of (i) fluctuations in mark-to-market derivative fair values associated with changes in the forward price curves for the commodities underlying our hedge contracts entered into and (ii) monthly settlements on our hedged derivative positions.
The following table presents gains and losses on our derivative instruments for the periods indicated:
 
Three Months Ended June 30,
(in thousands)
2020
 
2019
Settlement gains (losses)
$
(6,894
)
 
$
6,388

Non-cash mark-to-market derivative gain (loss)
(22,963
)
 
(4,260
)
Total
$
(29,857
)
 
$
2,128

Income Tax Expense. We recognized income tax benefit of $1.9 million and income tax expense of $5.9 million for the three months ended June 30, 2020 and 2019, respectively. The income tax benefit recognized in the second quarter of 2020 was primarily due to the release of a portion of our deferred tax asset valuation allowance during the period relating to our conversion of Class C to Class A shares during the quarter. Refer to Note 1—Basis of Presentation and Summary of Significant Accounting Policies for additional information on the conversion. The income tax expense recognized in the second quarter of 2019 was a result of pre-tax book income of $24.9 million during the period.
Our provisions for income taxes for the three months ended 2020 and 2019 differed from the amounts that would be provided by applying the statutory U.S. federal income tax rate of 21% to pre-tax book loss or income primarily due to (i) state income taxes; (ii) estimated permanent differences; and (iii) any changes during the period in our deferred tax asset valuation allowance, such as the $5.9 million reduction in the second quarter of 2020 that was mainly due to a discreet item recognized during the period for the decrease in deductions associated with stock award forfeitures and the conversion of Class C shares discussed above.



37

Six Months Ended June 30, 2020 Compared to Six Months Ended June 30, 2019
The following table provides the components of our net revenues and net production (net of all royalties, overriding royalties and production due to others) for the periods indicated, as well as each period’s average prices and average daily production volumes:
 
Six Months Ended June 30,
 
Increase/(Decrease)
 
2020
 
2019
 
$
 
%
Net revenues (in thousands):



 
 
 
 
Oil sales
$
243,605


$
389,859

 
$
(146,254
)
 
(38
)%
Natural gas sales
17,145


20,585

 
(3,440
)
 
(17
)%
NGL sales
22,528


48,364

 
(25,836
)
 
(53
)%
Oil and gas sales
$
283,278


$
458,808

 
$
(175,530
)
 
(38
)%
 



 
 
 
 
Average sales prices:



 
 
 
 
Oil (per Bbl)
$
33.92


$
51.51

 
$
(17.59
)
 
(34
)%
Effect of derivative settlements on average price (per Bbl)
(0.76
)

(0.20
)
 
(0.56
)
 
(280
)%
Oil net of hedging (per Bbl)
$
33.16


$
51.31

 
$
(18.15
)
 
(35
)%
 

 

 
 
 
 
Average NYMEX price for oil (per Bbl)
$
37.09


$
57.36

 
$
(20.27
)
 
(35
)%
Oil differential from NYMEX
(3.17
)

(5.85
)
 
2.68

 
46
 %
 

 

 
 
 
 
Natural gas (per Mcf)
$
0.82


$
1.09

 
$
(0.27
)
 
(25
)%
Effect of derivative settlements on average price (per Mcf)
(0.07
)

0.40

 
(0.47
)
 
(118
)%
Natural gas net of hedging (per Mcf)
$
0.75


$
1.49

 
$
(0.74
)
 
(50
)%
 

 

 
 
 
 
Average NYMEX price for natural gas (per Mcf)
$
1.76


$
2.69

 
$
(0.93
)
 
(35
)%
Natural gas differential from NYMEX
(0.94
)

(1.60
)
 
0.66

 
41
 %
 

 

 
 
 
 
NGL (per Bbl)
$
10.79


$
17.99

 
$
(7.20
)
 
(40
)%
 



 
 
 
 
Net production:



 
 
 
 
Oil (MBbls)
7,182


7,568

 
(386
)
 
(5
)%
Natural gas (MMcf)
20,855


18,918

 
1,937

 
10
 %
NGL (MBbls)
2,088


2,689

 
(601
)
 
(22
)%
Total (MBoe)(1)
12,746


13,410

 
(664
)
 
(5
)%
 



 
 
 
 
Average daily net production:



 
 
 
 
Oil (Bbls/d)
39,461


41,814

 
(2,353
)
 
(6
)%
Natural gas (Mcf/d)
114,585


104,521

 
10,064

 
10
 %
NGLs (Bbls/d)
11,474


14,856

 
(3,382
)
 
(23
)%
Total (Boe/d)(1)
70,333


74,089

 
(3,756
)
 
(5
)%
 
(1) 
Calculated by converting natural gas to oil equivalent barrels at a ratio of six Mcf of natural gas to one Boe.
Oil, Natural Gas and NGL Sales Revenues. Total net revenues for the six months ended June 30, 2020 were $175.5 million, or 38%, lower than total net revenues for the six months ended June 30, 2019. Revenues are a function of oil, natural gas and NGL volumes sold and average commodity prices realized.

38

Average realized sales prices for oil, natural gas and NGLs decreased in the first half of 2020 compared to the same 2019 period. The average price for oil before the effects of hedging decreased 34%, the average price for natural gas before the effects of hedging decreased 25% and the average price for NGLs decreased 40% between periods. The 34% decrease in the average realized oil price was mainly the result of lower NYMEX crude prices between periods (average NYMEX prices decreased 35%), which was minimally offset by improved oil differentials (a decrease of $2.68 per Bbl). The average realized sales price of natural gas decreased 25% due to lower average NYMEX gas prices between periods (average NYMEX prices decreased 35%), but this decrease was partially offset by improved gas differentials (a decrease of $0.66 per Mcf). The 40% decrease in average realized NGL prices between periods was primarily attributable to lower Mont Belvieu spot prices for plant products in the first half of 2020 compared to the first half of 2019. The market prices for oil, natural gas and NGLs were all significantly impacted by lower demand globally for oil and gas as a result of COVID-19 as well as commodity supply disruptions, both of which combined resulted in significant price declines starting in March 2020 as discussed in the market conditions section above.
Net production volumes for oil and NGLs decreased 5% and 22%, respectively, while natural gas production volumes increased 10% between periods. The oil production volume decrease was the result of (i) the temporary suspension of our drilling and completion activity in the second quarter of 2020, which resulted in only 26 new wells completed and brought online during the first half of 2020 as compared to 40 wells completed and brought online during the same 2019 period, (ii) the curtailment of a portion of our production during the month of May in the second quarter of 2020, and (iii) normal field production declines across our existing wells. These production decreases were partially offset by 70 operated wells placed on production in the Delaware Basin since the second quarter of 2020, which added 3,207 MBbls of net oil production to the six months ended June 30, 2020. Natural gas and NGLs are produced concurrently with our crude oil volumes, typically resulting in a high correlation between fluctuations in oil quantities sold and natural gas and NGL quantities sold. However, except for one month during the first half of 2020, the main processor of our raw gas operated in ethane-rejection as compared to operating in full ethane-recovery during the entire 2019 comparable period. As a result, we sold an increased amount of natural gas from our wet gas stream and recovered fewer NGLs during the 2020 period, resulting in an increase (10%) in natural gas volumes and a decrease (22%) in NGL volumes between periods.
Operating Expenses. The following table summarizes our operating expenses for the periods indicated:
 
Six Months Ended June 30,
 
Increase/(Decrease)
 
2020

2019
 
$
 
%
Operating costs (in thousands):



 
 
 
 
Lease operating expenses
$
58,478


$
64,747

 
$
(6,269
)
 
(10
)%
Severance and ad valorem taxes
22,269


33,306

 
(11,037
)
 
(33
)%
Gathering, processing and transportation expenses
34,223


31,267

 
2,956

 
9
 %
Operating costs per Boe:





 
 
 
 
Lease operating expenses
$
4.59


$
4.83

 
$
(0.24
)
 
(5
)%
Severance and ad valorem taxes
1.75


2.48

 
(0.73
)
 
(29
)%
Gathering, processing and transportation expenses
2.68


2.33

 
0.35

 
15
 %
Lease Operating Expenses. LOE for the six months ended June 30, 2020 decreased $6.3 million as compared to the six months ended June 30, 2019. Lower LOE for the first half of 2020 was primarily related to a $10.4 million decrease in workover expense between periods as a result of less workover activity. This decrease was offset by a $4.1 million increase in LOE costs associated with our higher well count. We had 381 gross operated horizontal wells as of June 30, 2020 compared to 302 gross operated horizontal wells as of June 30, 2019. The net increase in well count was mainly the result of our drilling activity adding 70 gross operated wells since the second quarter of 2019, which was further adjusted for acquisitions and divestitures.
LOE on a per Boe basis decreased when comparing the first half of 2020 to the same 2019 period. LOE per Boe was $4.59 for the six months ended June 30, 2020, which represents a decrease of $0.24 per Boe (or 5%) from the comparable 2019 period. This decrease in rate was mainly due to the lower level of workover activity, discussed above, as well as cost reduction initiatives we have undertaken such as (i) lowering contract labor costs, (ii) switching wells away from ESP lift to more reliable gas lift, and (iii) decreasing monthly equipment rentals, which were achieved by moving multiple wells off generators to more efficient electrical line-power. These decreases were partially offset by per BOE cost increases in the first half of 2020 compared to the same 2019 period associated with fixed and semi-variable costs that don’t decrease at the same rate as declines in production such as (i) wellhead chemical costs, (ii) electricity, (iii) water handling costs, and (iv) monthly rental fees for compressors.

39

Severance and Ad Valorem Taxes. Severance and ad valorem taxes for the six months ended June 30, 2020 decreased $11.0 million compared to the six months ended June 30, 2019. Severance taxes are primarily based on the market value of our production at the wellhead, while ad valorem taxes are generally based on the assessed taxable value of our proved developed oil and natural gas reserves and vary across the different counties in which we operate. Severance taxes for the first half of 2020 decreased $9.1 million compared to the same 2019 period primarily due to lower oil, natural gas and NGL revenues between periods. Ad valorem taxes also decreased $1.9 million between periods due to lower tax assessments on our oil and gas reserve values. Severance and ad valorem taxes as a percentage of total net revenues increased to 7.9% for the first half of 2020 as compared to 7.3% for the same 2019 period. This increase in rate was due to the ad valorem tax assessment, which while lower between periods (down 20%), declined less than our oil and gas sales which decreased 38% between periods.
Gathering, Processing and Transportation Expenses. GP&T for the six months ended June 30, 2020 increased $3.0 million compared to the six months ended June 30, 2019 primarily due to a $5.4 million decrease in reimbursements (net of related fees) received from third parties for their usage of our available FT capacity. This was partially offset by a $2.0 million decrease in plant processing, transportation and gathering fees incurred between periods.
On a per Boe basis, GP&T increased from $2.33 for the first half of 2019 to $2.68 per Boe for the same 2020 period. On a natural gas and NGL volume basis (i.e. excluding crude oil barrels) the Boe rate likewise increased between periods to $6.15 from $5.35 for the six months ended June 30, 2020 and 2019, respectively. These rate increases were mainly attributable to a lower amount of FT reimbursements (net of related fees) received from third parties for their usage of our available capacity as referenced above.
Depreciation, Depletion and Amortization. The following table summarizes our DD&A for the periods indicated:

Six Months Ended June 30,
(in thousands, except per Boe data)
2020
 
2019
Depreciation, depletion and amortization
$
194,278

 
$
208,672

Depreciation, depletion and amortization per Boe
$
15.24

 
$
15.56

Our DD&A rate can fluctuate as a result of finding and development costs incurred, acquisitions, impairments, as well as changes in proved developed and proved undeveloped reserves. For the six months ended June 30, 2020, DD&A expense amounted to $194.3 million, a decrease of $14.4 million over the same 2019 period. The primary factor contributing to lower DD&A expense in 2020 was the decrease in our overall production volumes between periods, which decreased DD&A expense by $10.2 million during the first half of 2020, while lower DD&A rates between periods lowered DD&A expense by $4.2 million.
DD&A per Boe was $15.24 for the first half of 2020 compared to $15.56 for the same period in 2019. This decrease in DD&A rate was primarily due to the proved property impairment recognized in the first quarter of 2020, which lowered the carrying value of our depletion base by $591.8 million. The effect of this impairment, however, was partially offset by downward revisions in our proved reserves during the first half of 2020, mainly due to lower SEC pricing and a higher level of infrastructure costs incurred in the trailing twelve months, which have no associated proved reserve adds.
Impairment and Abandonment Expense. During the six months ended June 30, 2020, $630.7 million of impairment and abandonment expense was incurred related to certain of our oil and natural gas properties. This expense consisted of (i) a $591.8 million non-cash impairment of our proved oil and gas properties as a result of depressed oil, natural gas and NGL commodity prices, and (ii) $38.9 million related to the amortization of leasehold expiration costs associated with individually insignificant unproved properties.
We review our proved oil and natural gas properties for impairment whenever events and circumstances indicate that the fair value of these assets may be below their carrying value. Fair values of our oil and natural gas properties are estimated using an income approach that is based on the discounted expected future net cash flows from these assets. These valuations are based on inputs which require significant judgment and include estimates of: (i) reserves; (ii) future production decline rates; (iii) future operating and development costs; (iv) future commodity prices, including price differentials; and (v) a market participant-based weighted average cost of capital rate.
We performed an impairment assessment of all our proved oil and gas properties as of March 31, 2020. Two of our fields were subject to impairment write-downs as quantified above, but the remaining five fields were not impaired due to their undiscounted cash flows exceeding their carrying values by 30% to over 100%. This impairment assessment was performed using commodity price futures curves as of March 31, 2020. If future oil, natural gas and NGL prices continue to decline to lower levels, or other estimates impacting future net cash flows deteriorate (e.g. reserves, price differentials, future operating and/or development costs), our proved oil and gas properties could be subject to additional impairment write-downs in future periods. We did not recognize any additional impairment write-downs with respect to our proved oil and gas properties for the three months ended June 30, 2020.

40

During the six months ended June 30, 2019, $35.7 million of impairment and abandonment expense was incurred related to undeveloped leasehold acreage. This expense consisted of (i) $19.1 million related to non-core acreage that expired during the first half of 2019 after efforts to extend, sell or trade these leases were unsuccessful, and (ii) $16.6 million for impaired acreage following an acreage sale initiated in the first quarter of 2019.
Exploration Expense. The following table summarizes our exploration expense for the periods indicated:  
 
Six Months Ended June 30,
(in thousands)
2020

2019
Geological and geophysical costs
$
3,074

 
$
4,812

Rig termination fees
3,046

 
283

Stock-based compensation
974

 
1,282

Severance payments
722

 
—

Other expenses
244

 
—

Exploration expense
$
8,060

 
$
6,377

Exploration was $8.1 million for the six months ended June 30, 2020 compared to $6.4 million for the same prior year period. Exploration expense mainly consists of topographical studies, G&G projects, and salaries and expenses of G&G personnel and includes other operating costs. The period over period increase was primarily due to (i) rig termination fees that were $2.8 million higher in the first half of 2020, as a result of reducing our operated drilling activity in 2020 and (ii) $0.7 million in nonrecurring severance payments to G&G personnel, resulting from our workforce reduction that was announced in the second quarter of 2020. These increases were partially offset by a $0.9 million decrease in G&G project and seismic study costs between periods and $0.8 million in lower ongoing G&G personnel costs in the 2020 period associated with the workforce reduction.
General and Administrative Expenses. The following table summarizes our G&A expenses for the periods indicated:  

Six Months Ended June 30,
(in thousands)
2020

2019
Cash general and administrative expenses
$
23,818

 
$
24,594

Stock-based compensation
10,162

 
11,959

Severance payments
2,884

 
—

General and administrative expenses
$
36,864

 
$
36,553

G&A expenses for the six months ended June 30, 2020 were $36.9 million compared to $36.6 million for the six months ended June 30, 2019. The higher G&A expenses incurred in the first half of 2020 were primarily due to nonrecurring charges for (i) $2.9 million of severance payments to G&A employees included in the reduction to our workforce (which was discussed above in the results for the three months ended June 30, 2020) and (ii) $0.5 million in transaction costs that were expensed when the water disposal asset sale was terminated and are included in cash G&A (see Note 2—Property Divestiture for additional information). In addition, cash G&A expenses increased by $0.7 million between periods due to higher software costs, corporate insurance premiums and professional fees. These increases were partially offset by (i) a $1.8 million decrease in stock compensation expense between periods primarily related to modifications and forfeitures of stock awards included in the workforce reduction (refer to Note 6—Stock-Based Compensation for additional information) and (ii) a $1.9 million decrease in employee payroll costs, which was attributable to our workforce reduction as well as compensation decreases taken by employees that remained.

41

Other Income and Expenses. 
Interest Expense. The following table summarizes our interest expense for the periods indicated:
 
Six Months Ended June 30,
(in thousands)
2020
 
2019
Credit facility
$
5,326

 
$
4,611

8.00% Senior Secured Notes due 2025
1,129

 
—

5.375% Senior Unsecured Notes due 2026
10,106

 
10,750

6.875% Senior Unsecured Notes due 2027
16,118

 
10,122

Amortization of debt issuance costs and discount
2,334

 
1,287

Interest capitalized
(1,221
)
 
(2,173
)
Total
$
33,792

 
$
24,597

Interest expense was $9.2 million higher for the six months ended June 30, 2020 compared to the same 2019 period. The higher interest expense incurred in the first half of 2020 was mainly due to (i) $6.0 million in increased interest expense related to our 2027 Senior Notes, that were issued in March 2019 and only outstanding for three and half months during the prior year period, (ii) $1.1 million in interest incurred on our Senior Secured Notes issued in May of 2020 in connection with the Debt Exchange, (iii) $1.0 million in higher amortization related to debt issuance costs and debt discount recognized in connection with the Debt Exchange, and (iv) $0.7 million in increased interest expense incurred on our credit facility borrowings. These increases were partially offset by lower interest expense incurred on our Senior Unsecured Notes during the second quarter of 2020, as a result of the Debt Exchange discussed in Note 4—Long-Term Debt under Part I, Item I of this Quarterly Report.
Our weighted average borrowings outstanding under our credit facility were $311.6 million and $158.0 million for the first half of 2020 and 2019, respectively. Our credit facility’s weighted average effective interest rate (which is a LIBOR-based rate) was 3.0% and 4.2% for the six months ended June 30, 2020 and 2019, respectively. LIBOR was lower in the first half of 2020 versus the same prior year period.
Gain on exchange of debt. A gain of $143.4 million was recognized for the six months ended June 30, 2020 related to our opportunistic Debt Exchange that was executed in the second quarter of 2020. This gain was determined based on the difference between the carrying value of the Senior Unsecured Notes extinguished less the fair value at the date of issuance of our newly issued Senior Secured Notes. Refer to Note 4—Long-Term Debt for additional information regarding the gain on exchange of debt.
Net Gain (Loss) on Derivative Instruments. Net gains and losses are a function of (i) fluctuations in mark-to-market derivative fair values associated with changes in the forward price curves for the commodities underlying our hedge contracts entered into and (ii) monthly settlements of our hedged derivative positions.
The following table presents gains and losses for derivative instruments for the periods indicated:
 
Six Months Ended June 30,
(in thousands)
2020
 
2019
Settlement gains (losses)
$
(6,947
)
 
$
6,011

Non-cash mark-to-market derivative gain (loss)
(31,415
)
 
(9,754
)
Total
$
(38,362
)
 
$
(3,743
)
Income Tax Expense. We recognized income tax benefit of $85.1 million and income tax expense of $3.7 million for the six months ended June 30, 2020 and 2019, respectively. The income tax benefit recognized in the first half of 2020 was primarily due to a pre-tax book loss incurred of $630.1 million, whereas the income tax expense recognized in the first half of 2019 was a result of pre-tax book income of $14.1 million during the period. Our provisions for income taxes for the first half of 2020 and 2019 differed from the amounts that would be provided by applying the statutory U.S. federal income tax rate of 21% to pre-tax book income (loss) primarily due to (i) state income taxes; (ii) estimated permanent differences; and (iii) any changes during the period in our deferred tax asset valuation allowance, such as the recognition of a $49.7 million valuation allowance in the first half of 2020 against net operating loss carryforwards that are not expected to be realized.

42

Liquidity and Capital Resources
Overview
Our drilling and completion and land acquisition activities require us to make significant capital expenditures. Historically, our primary sources of liquidity have been cash flows from operations, borrowings under CRP’s revolving credit facility, and proceeds from offerings of debt or equity securities. Future cash flows are subject to a number of variables, including oil and natural gas prices. Prices for oil and natural gas began to decline significantly in March 2020 and continued to deteriorate and have remained volatile since. These lower commodity prices negatively impact our cash flows and availability to access debt or equity markets, and sustained low oil and natural gas prices could have a material and adverse effect on our liquidity position. To date, our primary use of capital has been for drilling and development capital expenditures and the acquisition of oil and natural gas properties. The following table summarizes our capital expenditures (“capex”) incurred for the six months ended June 30, 2020:
(in millions)
Six Months Ended June 30, 2020
Drilling and completion capital expenditures
$
168.2

Facilities, infrastructure and other
31.7

Land
3.5

Total capital expenditures
$
203.4

We continually evaluate our capital needs and compare them to our capital resources. As a result of the decline in crude oil prices and ongoing uncertainty regarding the oil supply-demand macro environment, we temporarily suspended all drilling and completion activities at the end of the first quarter of 2020 in order to preserve capital. Specifically, we reduced our operated drilling rig program to zero rigs starting in April of 2020 and continued with no rigs in operation for the remainder of the second quarter, which is down from the four-rig program that we initially announced with our 2020 operational guidance at the beginning of the year. We plan to resume drilling activity in the fourth quarter of 2020 with a one-rig program and will begin to complete wells that were previously drilled but uncompleted in the third quarter of 2020. Consequently, we expect our total capex budget for 2020 will now be between $240.0 million to $270.0 million, which represents an approximate 60% reduction from the mid-point of our original estimated capex budget for 2020 of $590 million to $690 million.
Because we are the operator of a high percentage of our acreage, we can control the amount and timing of our capital expenditures. We can choose to defer or accelerate a portion of our planned capex depending on a variety of factors, including but not limited to: prevailing and anticipated prices for oil and natural gas; oil storage or transportation constraints; the success of our drilling activities; the availability of necessary equipment, infrastructure and capital; the receipt and timing of required regulatory permits and approvals; seasonal conditions; property or land acquisition costs; and the level of participation by other working interest owners.
Given the weakness in realized oil prices, we voluntarily curtailed or shut-in a portion of our second quarter 2020 production volumes. Specifically, we curtailed approximately 20% of our production during the month of May, but were able to bring the majority of our production back online in June as crude oil prices recovered. The potential for any future curtailment decisions will continue to be evaluated and made on a month-to-month basis subject to market conditions, storage and transportation constraints, and contractual obligations. Any decision in the future to further curtail or shut-in our production could adversely affect our business, financial condition, results of operations, liquidity, and ability to finance planned capital expenditures.
We expect to fund the remainder of our 2020 capital expenditures with cash flows from operations and borrowings under our credit agreement. We cannot ensure that cash flows from operations will be available or other sources of needed capital on acceptable terms or at all. Further, our ability to access the public or private debt or equity capital markets at economic terms in the future will be affected by general economic conditions, the domestic and global oil and financial markets, our operational and financial performance, the value and performance of our debt or equity securities, prevailing commodity prices and other macroeconomic factors outside of our control.
Moreover, to manage our future financing cash outflows and liquidity position, we completed the Debt Exchange with respect to our Senior Unsecured Notes in May 2020 which reduced the total principal amounts due of our aggregated secured and unsecured notes by $127.1 million and also reduced future interest payments.

43

Analysis of Cash Flow Changes
The following table summarizes our cash flows for the periods indicated:
 
Six Months Ended June 30,
(in thousands)
2020
 
2019
Net cash provided by operating activities
$
84,503

 
$
280,194

Net cash used in investing activities
(277,050
)
 
(458,520
)
Net cash provided by financing activities
189,558

 
188,643

For the six months ended June 30, 2020, we generated $84.5 million of cash from operating activities, a decrease of $195.7 million from the same period in 2019. Cash provided by operating activities decreased primarily due to lower realized prices for all commodities, lower production volumes for crude oil and NGLs, higher GP&T costs, exploration expense, cash G&A expenses, interest payments, cash settlement losses from derivatives, and the timing of supplier payments during the six months ended June 30, 2020. These declining factors were partially offset by lower lease operating expenses, production taxes, and the timing of our receivable collections for the six months ended June 30, 2020 as compared to the same 2019 period. Refer to “Results of Operations” for more information on the impact of volumes and prices on revenues and for more information on fluctuations in our operating expenses between periods.
During the six months ended June 30, 2020, cash flows from operating activities, cash on hand, and net borrowings of $195.0 million under our credit facility were used to finance $271.4 million of drilling and development capex, to fund $6.1 million in oil and gas property acquisitions, and to finance $5.1 million of debt issuance and exchange costs.
During the six months ended June 30, 2019, cash flows from operating activities, proceeds from sales of oil and gas properties and proceeds from the issuance of our 2027 Senior Notes were used to repay net borrowings of $300.0 million under our credit facility, to finance $437.9 million of drilling and development capex, to fund $42.3 million in oil and gas property acquisitions, and to purchase $4.3 million of other property and equipment.
Credit Agreement
CRP, our consolidated subsidiary, has a credit agreement with a syndicate of banks that provides for a five-year secured revolving credit facility, maturing on May 4, 2023 (the “Credit Agreement”). On May 1, 2020, CRP, as borrower, and we, as parent guarantor, entered into the 2020 Amendments, which, among other things, established a new borrowing base and level of elected commitments of $700.0 million. The 2020 Amendments that the lenders approved permitted the issuance of the Senior Secured Notes in connection with the Debt Exchange (discussed below), and they implemented an availability blocker equal to 25% of the newly issued amount of Senior Secured Notes. As of June 30, 2020, we had $370.0 million in borrowings outstanding and $290.0 million in available borrowing capacity, which was net of $8.2 million in letters of credit outstanding and the availability blocker of $31.8 million.
CRP’s Credit Agreement contains restrictive covenants that limit its ability to, among other things: (i) incur additional indebtedness; (ii) make investments and loans; (iii) enter into mergers; (iv) make or declare dividends; (v) enter into commodity hedges exceeding a specified percentage of our expected production; (vi) enter into interest rate hedges exceeding a specified percentage of its outstanding indebtedness; (vii) incur liens; (viii) sell assets; and (ix) engage in transactions with affiliates.
CRP’s Credit Agreement also requires us to maintain compliance with the following financial ratios:
(i) a current ratio, which is the ratio of CRP’s consolidated current assets (including unused commitments under its revolving credit facility and excluding non-cash derivative assets and certain restricted cash) to its consolidated current liabilities (excluding any current portion of long-term debt due under the credit agreement and non-cash derivative liabilities), of not less than 1.0 to 1.0;
(ii) a first lien leverage ratio, as defined within the Credit Agreement as the ratio of first lien debt to EBITDAX for the rolling four fiscal quarter period, which may not exceed 2.75 to 1.00 beginning with the quarter ending June 30, 2020 and extending through the quarter ending December 31, 2021, after which the maximum ratio shall decrease to 2.50 to 1.00 for each of the quarters ending in 2022; and
(iii) a leverage ratio, as defined with the Credit Agreement as the ratio of total funded debt to consolidated EBITDAX for the rolling four fiscal quarter period. Pursuant to the 2020 Amendments, the leverage ratio is suspended until March 31, 2022, at which time, the ratio may not exceed 5.00 to 1.00, with such maximum ratio declining at a rate of 0.25 for each succeeding quarter until March 31, 2023 when the ratio is set at not greater than 4.0 to 1.0.
CRP was in compliance with the covenants and the financial ratios described above as of June 30, 2020 and through the filing of this Quarterly Report.

44

For further information on the Credit Agreement, refer to Note 4—Long-Term Debt under Part I, Item I of this Quarterly Report.
Senior Unsecured Note Debt Exchange and Senior Secured Notes
On May 22, 2020, CRP completed the Debt Exchange pursuant to which $110.6 million aggregate principal amount of CRP’s 2026 Senior Notes and $143.7 million aggregate principal amount of CRP’s 2027 Senior Notes were validly tendered and exchanged by certain eligible bondholders for consideration consisting of $127.1 million aggregate principal amount of newly issued Senior Secured Notes. The Senior Secured Notes bear interest at an annual rate of 8% and are due on June 1, 2025. Interest is payable semi-annually in arrears on each June 1 and December 1, commencing on December 1, 2020.
The Debt Exchange was accounted for as a troubled debt restructuring in accordance with ASC 470-60. Thus, the carrying value of the Senior Secured Notes includes undiscounted amounts of both principal and future interest payments. As of June 30, 2020, $51.1 million of future interest on the Senior Secured Notes has been recognized as long-term debt in our consolidated balance sheets, which payable balance will be reduced as semi-annual interest payments are made. As a result, future interest expense reflected in our Consolidated Statements of Operations will be significantly lower than our actual cash interest payments.
The Senior Secured Notes are guaranteed, subject to certain exceptions, by us and each of CRP’s subsidiaries and are secured on a second-priority basis (subject in priority only to certain exceptions) by substantially all of CRP’s and our assets, including deposit accounts and substantially all proved reserves and undeveloped acreage.
Senior Unsecured Notes
On November 30, 2017, CRP issued $400.0 million of 5.375% senior notes due 2026 and on March 15, 2019, CRP issued $500.0 million of 6.875% senior notes due 2027 in 144A private placements. The Senior Unsecured Notes are fully and unconditionally guaranteed on a senior unsecured basis by the Company and each of CRP’s current subsidiaries that guarantee CRP’s revolving credit facility.
In May 2020, a portion of Senior Unsecured Notes were exchanged for Senior Secured Notes (see above discussion for details of the exchange).
The indentures governing the Senior Unsecured Notes and Senior Secured Notes (collectively, the “Senior Notes”) contain covenants that, among other things and subject to certain exceptions and qualifications, limit CRP’s ability and the ability of CRP’s restricted subsidiaries to: (i) incur or guarantee additional indebtedness or issue certain types of preferred stock; (ii) pay dividends on capital stock or redeem, repurchase or retire capital stock or subordinated indebtedness; (iii) transfer or sell assets; (iv) make investments; (v) create certain liens; (vi) enter into agreements that restrict dividends or other payments from their subsidiaries to them; (vii) consolidate, merge or transfer all or substantially all of their assets; (viii) engage in transactions with affiliates; and (ix) create unrestricted subsidiaries. CRP was in compliance with these covenants as of June 30, 2020 and through the filing of this Quarterly Report.
For further information on any of our Senior Notes issuances, refer to Note 4—Long-Term Debt under Part I, Item I of this Quarterly Report.
Contractual Obligations
Our contractual obligations include operating and transportation agreements, drilling rig contracts, office and equipment leases, asset retirement obligations, long-term debt obligations and cash interest expense on long-term debt obligations, which we routinely enter into, modify or extend. Since December 31, 2019, there have not been any significant, non-routine changes in our contractual obligations, other than the changes to certain of our operating lease commitments and principal and interest due under our Senior Unsecured Notes as a result of the Debt Exchange discussed above. Refer to Note 13—Leases under Part I, Item I of this Quarterly Report for updated contractual obligations associated with our operating leases as of June 30, 2020.
Critical Accounting Policies and Estimates
There have been no material changes during the six months ended June 30, 2020 to the critical accounting policies previously disclosed in our 2019 Annual Report. Please refer to Part II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Critical Accounting Policies and Estimates in our 2019 Annual Report for a discussion of our critical accounting policies and estimates.
New Accounting Pronouncements
There were no significant new accounting standards adopted or new accounting pronouncements that would have a potential effect on us as of June 30, 2020.

45

Item 3. Quantitative and Qualitative Disclosures About Market Risk
The term “market risk” as it applies to our business refers to the risk of loss arising from adverse changes in oil and natural gas prices and interest rates, and we are exposed to market risk as described below. The primary objective of the following information is to provide quantitative and qualitative information about our potential exposure to market risks. The disclosures are not meant to be precise indicators of expected future losses, but rather indicators of reasonably possible losses. All of our market risk sensitive instruments were entered into for purposes other than speculative trading.
Commodity Price Risk
Our primary market risk exposure is in the pricing that we receive for our oil, natural gas and NGL production. Pricing for oil, natural gas and NGLs has been volatile and unpredictable for several years, and we expect this volatility to continue for the foreseeable future. Based on our production for the first half of 2020, our oil and gas sales for the six months ended June 30, 2020 would have moved up or down $24.4 million for each 10% change in oil prices per Bbl, $2.3 million for each 10% change in NGL prices per Bbl, and $1.7 million for each 10% change in natural gas prices per Mcf.
Due to this volatility, we have historically used, and we may elect to continue to selectively use, commodity derivative instruments (such as collars, swaps and basis swaps) to mitigate price risk associated with a portion of our anticipated production. Our derivative instruments allow us to reduce, but not eliminate, the potential effects of the variability in cash flows from operations due to fluctuations in oil and natural gas prices and thereby provide increased certainty of cash flows for our drilling program and debt service requirements. These instruments provide only partial price protection against declines in oil and natural gas prices, but alternatively they may partially limit our potential gains from future increases in prices. Our credit agreement limits our ability to enter into commodity hedges covering greater than 85% of our reasonably anticipated projected production from proved properties.
The following table summarizes the terms of the swap contracts we had in place as of June 30, 2020 and additional contracts entered into through July 31, 2020. Refer to Note 7—Derivative Instruments in Item 1 of Part I of this Quarterly Report for open derivative positions as of June 30, 2020:
 
Period
 
Volume (Bbls)
 
Volume
(Bbls/d)
 
Weighted Average
Fixed Price ($/Bbl)(1)
Crude oil swaps
 
 
 
 
 
 
 
NYMEX WTI
July 2020 - September 2020
 
2,300,000

 
25,000

 
$
26.83

 
October 2020 - December 2020
 
1,196,000

 
13,000

 
38.89

 
 
 
 
 
 
 
 
ICE Brent
January 2021 - March 2021
 
90,000

 
1,000

 
45.56

 
 
 
 
 
 
 
 
 
Period
 
Volume (Bbls)
 
Volume
(Bbls/d)
 
Weighted Average Differential ($/Bbl)(2)
Crude oil basis swaps
July 2020 - September 2020
 
1,472,000

 
16,000

 
$
0.52

 
October 2020 - December 2020
 
1,196,000

 
13,000

 
0.51

 
 
 
 
 
 
 
 
 
Period
 
Volume (Bbls)
 
Volume
(Bbls/d)
 
Weighted Average Collar Price Ranges(3)
Crude oil collars
October 2020 - December 2020
 
184,000

 
2,000

 
$39.00 - $44.50
 
(1) 
These crude oil swap transactions are settled based on the NYMEX WTI or ICE Brent oil price on each trading day within the specified monthly settlement period.
(2) 
These oil basis swap transactions are settled based on the difference between the arithmetic average of ARGUS MIDLAND WTI and ARGUS WTI CUSHING indices, during each applicable settlement period.
(3) 
These crude oil collars are settled based on the NYMEX WTI price on each trading day within the specified monthly settlement period and establish floor and ceiling prices for the contractual volumes.

46


Period
 
Volume (MMBtu)
 
Volume (MMBtu/d)
 
Weighted Average Fixed Price ($/MMBtu)(1)
Natural gas swaps
July 2020 - September 2020
 
2,760,000

 
30,000

 
$
2.03

 
October 2020 - December 2020
 
2,150,000

 
23,370

 
2.40

 
January 2021 - March 2021
 
1,800,000

 
20,000

 
2.68

 
 
 
 
 
 
 
 

Period
 
Volume (MMBtu)
 
Volume (MMBtu/d)
 
Weighted Average Differential ($/MMBtu)(2)
Natural gas basis swaps
July 2020 - September 2020
 
2,760,000

 
30,000

 
$
(1.62
)
 
October 2020 - December 2020
 
930,000

 
10,109

 
(1.62
)
 
(1) 
These natural gas swap contracts are settled based on the NYMEX Henry Hub price on each trading day within the specified monthly settlement period.
(2) 
These natural gas basis swap contracts are settled based on the difference between the Inside FERC’s West Texas WAHA price and the NYMEX price of natural gas, during each applicable settlement period.
Changes in the fair value of derivative contracts from December 31, 2019 to June 30, 2020, are presented below:
(in thousands)
 
Commodity derivative asset (liability)
Net fair value of oil and gas derivative contracts outstanding as of December 31, 2019
 
$
(325
)
Contract settlements
 
6,947

Change in the futures curve of forecasted commodity prices(1)
 
(38,362
)
Net fair value of oil and gas derivative contracts outstanding as of June 30, 2020
 
$
(31,740
)
 
(1) 
At inception, new derivative contracts entered into by us have no intrinsic value.
A hypothetical upward or downward shift of 10% per Bbl in the NYMEX forward curve for crude oil as of June 30, 2020 would cause a $13.8 million increase or decrease, respectively, in this fair value liability, and a hypothetical upward or downward shift of 10% per Mcf in the NYMEX forward curve for natural gas as of June 30, 2020 would cause a $1.3 million increase or decrease, respectively, in this same fair value liability.
Interest Rate Risk
Our ability to borrow and the rates offered by lenders can be adversely affected by deteriorations in the credit markets and/or downgrades in our credit rating. The uncertainties regarding the impact of COVID-19 as well as the significant decline in global oil and gas prices in March and April of 2020 has impacted the credit markets, resulting in increases in market interest rates for new debt issuances. CRP’s credit facility interest rate, on the other hand, is based on a LIBOR spread, which exposes us to interest rate risk on our borrowings outstanding to the extent LIBOR increases.
As of June 30, 2020, we had $370.0 million of debt outstanding under our credit agreement, with a weighted average interest rate of 3.5%. Assuming no change in the amount outstanding, the impact on interest expense of a 1.0% increase or decrease in the assumed weighted average interest rate would be approximately $3.7 million per year. We do not currently have or intend to enter into any derivative arrangements to protect against fluctuations in interest rates applicable to our outstanding indebtedness.
The remaining long-term debt balance of $736.0 million consists of our Senior Notes, which have fixed interest rates. Therefore, this balance is not affected by interest rate movements. For additional information regarding our debt instruments, see Note 4—Long-Term Debt, in Item 1 of Part I of this Quarterly Report.

47

Item 4. Controls and Procedures
Evaluation of Disclosure Control and Procedures
In accordance with Rules 13a-15 and 15d-15 under the Exchange Act, we have evaluated, under the supervision and with the participation of management, including our principal executive officer and principal financial officer, the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of June 30, 2020. Our disclosure controls and procedures are designed to provide reasonable assurance that the information required to be disclosed in reports that we file under the Exchange Act is accumulated and communicated to our management, including our principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure and is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the SEC. Based upon that evaluation, our principal executive officer and principal financial officer concluded that our disclosure controls and procedures were effective as of June 30, 2020 at the reasonable assurance level.
Changes in Internal Control over Financial Reporting
There were no changes in the system of internal control over financial reporting (as defined in Rule 13a-15(f) and Rule 15d-15(f) under the Exchange Act) during the three months ended June 30, 2020 that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.
PART II.  OTHER INFORMATION

Item 1. Legal Proceedings
From time to time, we are party to ongoing legal proceedings in the ordinary course of business, including workers’ compensation claims and employment-related disputes. While the outcome of these proceedings cannot be predicted with certainty, we believe it is remote that the results of such proceedings, individually or in the aggregate, that are reasonably possible to occur will have a material adverse effect on our business, financial condition, results of operations or liquidity.
Item 1A. Risk Factors
In addition to the other information set forth in this Quarterly Report, you should carefully consider the risk factors and other cautionary statements described under the heading “Item 1A. Risk Factors” included in our 2019 Annual Report and the risk factors and other cautionary statements contained in our other SEC filings as well as additional risk factors set forth below. Other than with respect to the additional risk factors below, there have been no material changes in our risk factors from those described in our 2019 Annual Report. The risks described in the 2019 Annual Report and below are not the only risks facing us. Additional risks and uncertainties not currently known to us or that we currently deem to be immaterial also may materially adversely affect our business, financial condition or future results.
 The excess supply of oil and natural gas resulting from the reduced demand caused by the COVID-19 pandemic and the effects of actions by, or disputes among or between, oil and natural gas producing countries may result in transportation and storage constraints, reduced production and shut-in of our wells, any of which would adversely affect our business, financial condition, results of operations, liquidity, and ability to finance planned capital expenditures.
The recent worldwide outbreak of COVID-19, the uncertainty regarding the impact of COVID-19 and various governmental actions taken to mitigate the impact of COVID-19, have resulted in an unprecedented decline in demand for oil and natural gas. At the same time, the decision by Saudi Arabia in March 2020 to drastically reduce export prices and increase oil production followed by the curtailment agreements amongst OPEC and other countries such as Russia further increased uncertainty and volatility around global oil supply-demand dynamics. To the extent that the outbreak of COVID-19 continues to negatively impact demand and OPEC members, other oil exporting nations, and oil producers fail to implement production cuts or take other actions that are sufficient to support and stabilize commodity prices, we expect there to be excess supply of oil and natural gas for a sustained period.
This excess supply has and could, in turn, continue to result in transportation and storage capacity constraints in the United States, or even the elimination of available storage, including in the Permian Basin. If, in the future, our transportation or storage arrangements become constrained or unavailable, we may incur significant operational costs if there is an increase in price for services or we may be required to shut-in or curtail production or flare our natural gas. In addition, given the weakness in realized oil prices, we voluntarily curtailed or shut-in a portion of our second quarter 2020 production volumes. Further potential curtailment decisions will continue to be evaluated and made on a month-to-month basis subject to market conditions, storage or transportation constraints, and contractual obligations. Our actions to shut-in wells may result in obligations to pay certain demand charges for gathering and processing services and firm transportation charges for pipeline capacity we have reserved. Further, any prolonged shut-in of our wells may result in materially decreased well productivity once we are able to resume

48

operations, and any cessation of drilling and development of our acreage could result in the expiration, in whole or in part, of our leases. These impacts on our operations, together with the lower price we receive for our continuing production of oil and gas, could impact our ability to comply with the covenants under CRP’s credit agreement and Senior Notes. All of these impacts resulting from the confluence of the COVID-19 pandemic and the price war between Saudi Arabia and Russia may adversely affect our business, financial condition, results of operations, liquidity, and ability to finance planned capital expenditures.
Due to the commodity price environment, we have postponed or eliminated a portion of our developmental drilling. A sustained period of weakness in oil, natural gas and NGLs prices, and the resultant effects of such prices on our drilling economics and ability to raise capital, will require us to reevaluate and further postpone or eliminate additional drilling. Such actions would likely result in the reduction of our proved undeveloped reserves and related reserve values and a reduction in our ability to service our debt obligations.
Additionally, as of December 31, 2019, approximately 13% of our total net acreage was not held by production and we had leases representing 3,162 and 3,750 undeveloped net acres scheduled to expire during 2020 and during 2021, respectively, in each case assuming no exercise of lease extension options where applicable. Our actions to curtail production and shut-in wells, together with any further curtailments we may implement in the future, may result in our inability to continue to hold such leases that are scheduled to expire, which may further reduce our reserves. As a result, if oil, natural gas and/or NGL prices experience a sustained period of weakness, our future business, financial condition, results of operations, liquidity, and ability to finance planned capital expenditures may be materially and adversely affected.
Our production is not fully hedged, and we are exposed to fluctuations in oil, natural gas and NGL prices and will be affected by continuing and prolonged declines in oil, natural gas and NGL prices.
Our production is not fully hedged, and we are exposed to fluctuations in oil, natural gas and NGL prices and will be affected by continuing and prolonged declines in oil, natural gas and NGL prices. We have entered into fixed price oil swaps for July through March of 2021 to protect against possible, additional near-term declines in oil prices. During this period, CRP has hedged an average of approximately 13,000 barrels per day of oil at a weighted average price of $31.32 per Bbl. We intend to continue to hedge our production, but we may not be able to do so at favorable prices. Accordingly, our revenues and cash flows are subject to increased volatility and may be subject to significant reduction in prices which would have a material negative impact on our results of operations.
If commodity prices continue to decrease or remain at current levels such that our future undiscounted cash flows from our properties are less than their carrying value, we may be required to take additional write-downs of the carrying values of our properties.
Accounting guidance requires that we periodically review the carrying value of our properties for possible impairment. Based on prevailing commodity prices and specific market factors and circumstances at the time of prospective impairment reviews, and the continuing evaluation of development plans, production data, economics and other factors, we may be required to write-down the carrying value of our properties. A write-down constitutes a non-cash charge to earnings. Due to the recent depressed commodity prices, we recorded a $591.8 million non-cash impairment to the carrying value of our oil and natural gas properties, which had an adverse effect on our results of operations. Further impairments will be required if oil and natural gas prices remain low or decline further, our undeveloped property leases expire in whole or in part, estimated proved reserve volumes are revised downward or the net capitalized cost of proved oil and gas properties otherwise exceeds the present value of estimated future net cash flows.
The Pre-Tax PV10% of our proved reserves at December 31, 2019 may not be the same as the current market value of our estimated oil, natural gas and NGLs reserves.
You should not assume that the Pre-Tax PV10% value of our proved reserves as of December 31, 2019 as disclosed in our 2019 Annual Report is the current market value of our estimated oil, natural gas and NGLs reserves. We base the discounted future net cash flows from our proved reserves on the 12-month first-day-of-the-month oil and natural gas average prices without giving effect to derivative transactions. Actual future net cash flows from our oil and natural gas properties will be affected by factors such as:
•
the actual prices we receive for oil, natural gas and NGLs;
•
the actual development and production expenditures;
•
the amount and timing of actual production; and
•
changes in governmental regulations or taxation.
The timing of both our production and expenses incurred in connection with the development and production of oil and natural gas properties will affect the timing and amount of actual future net revenues from proved reserves, and thus their actual present value. In addition, the 10% discount factor we use when calculating Pre-Tax PV10% may not be the most appropriate

49

discount factor based on interest rates in effect from time to time and risks associated with us or the oil and natural gas industry in general. Actual future prices and costs may differ materially from those used in the present value estimates included in the Annual Report, which could have a material effect on the value of our reserves. The oil and natural gas prices used in computing our Pre-Tax PV10% as of December 31, 2019 under SEC guidelines were $52.19 per Bbl and $2.58 per MMBtu, respectively, before price differentials. Using more recent prices in estimating proved reserves results in a reduction in proved reserve volumes due to economic limits, which would further reduce the Pre-Tax PV10% value of our proved reserves.
The marketability of our production is dependent upon transportation and other facilities, certain of which we do not control. If these facilities are unavailable, or if we are unable to access these facilities on commercially reasonable terms, our operations could be interrupted and our revenues reduced.
The marketability of our oil, natural gas and NGL production depends in part upon the availability, proximity, capacity and availability of transportation and storage facilities owned by third parties. In general, we do not control these facilities, and our access to them may be limited or denied. Our oil production is generally transported from the wellhead to our tank batteries by a gathering system. Our purchasers then transport the oil by pipeline to a larger pipeline for transportation to markets. The majority of our natural gas production is generally transported by gathering lines from the wellhead to a central delivery point and is then gathered by third-party lines to a gas processing facility. We do not control these third-party transportation, gathering or processing facilities and our access to them may be limited or denied. Insufficient production from our wells to support the construction of pipeline facilities by our purchasers or a significant disruption in the availability of third-party transportation facilities or other production facilities could adversely impact our ability to deliver to market or produce our production and thereby cause a significant interruption in our operations.
If we cannot meet the continued listing requirements of the Nasdaq, the Nasdaq may delist our common stock, which would have an adverse impact on the trading volume, liquidity and market price of our common stock.
On April 21, 2020, we received written notification (the “Notice”) from the Listing Qualifications Department of the Nasdaq Stock Market LLC (“Nasdaq”) indicating that, for the last thirty consecutive business days, the bid price for our Class A Common Stock, par value $0.0001 per share (our “Common Stock”), had closed below the minimum $1.00 per share requirement for continued listing on the Nasdaq Capital Market under Nasdaq Listing Rule 5550(a)(2) (the “Minimum Bid Requirement”). Subsequently, on June 8, 2020, the Company received written notification from Nasdaq communicating that the Company has regained compliance with the Minimum Bid Requirement as a result of the Closing Stock Price remaining above $1.00 per share for 10 consecutive business days, and the matter is now closed.
However, our stock has recently fallen back below $1.00 and, unless the share price increases in the near-term, we will receive another notification of delisting. We are required to meet the continued listing requirement for market value of publicly held shares and all other initial listing standards for the Nasdaq Capital Market or cure any deficiency within the applicable timeframes.
We intend to actively monitor the closing bid price of our Common Stock and will evaluate available options to remain within or regain compliance with the Minimum Bid Requirement, as necessary. There can be no assurance that we will be able to remain within or regain compliance with the Minimum Bid Requirement or maintain compliance with the other listing requirements of the Nasdaq. If our Common Stock ultimately were to be delisted for any reason, it could negatively impact us as it would likely reduce the liquidity and market price of our Common Stock; reduce the number of investors willing to hold or acquire our Common Stock; and negatively impact our ability to access equity markets and obtain financing.

50

Item 6. Exhibits
Exhibit
Number
 
Description of Exhibit
3.1
 
3.2
 
3.3
 
3.4
 
3.5
 
3.6
 
4.1
 
4.2
 
4.3
 
4.4
 
10.1#
 
10.2
 
10.3#
 
10.4
 
10.5
 
10.6
 
10.7*#
 
10.8*#
 
31.1*
 
31.2*
 
32.1*
 
32.2*
 
101.INS*
 
Inline XBRL Instance Document - The instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document.
101.SCH*
 
Inline XBRL Taxonomy Extension Schema Document.
101.CAL*
 
Inline XBRL Taxonomy Extension Calculation Linkbase Document.
101.DEF*
 
Inline XBRL Taxonomy Extension Definition Linkbase Document.
101.LAB*
 
Inline XBRL Taxonomy Extension Label Linkbase Document.

51

101.PRE*
 
Inline XBRL Taxonomy Extension Presentation Linkbase Document.
#    Management contract or compensatory plan or agreement.
*    Filed herewith.

52

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 thereto duly authorized.
 
CENTENNIAL RESOURCE DEVELOPMENT, INC.
 
 
 
 
By:
/s/ GEORGE S. GLYPHIS
 
 
George S. Glyphis
Vice President, Chief Financial Officer and Assistant Secretary
 
 
 
 
Date:
August 3, 2020


53

EXHIBIT 10.7

CENTENNIAL RESOURCE DEVELOPMENT, INC.
2016 LONG TERM INCENTIVE PLAN
CASH-SETTLED PERFORMANCE RESTRICTED STOCK UNIT GRANT NOTICE
Capitalized terms not specifically defined in this Cash-Settled Performance Restricted Stock Unit Grant Notice (the “Grant Notice”) have the meanings given to them in the 2016 Long Term Incentive Plan (as amended and/or restated from time to time, the “Plan”) of Centennial Resource Development, Inc. (the “Company”).
The Company has granted to the participant listed below (“Participant”) the Restricted Stock Units described in this Grant Notice (the “PSUs”), subject to the terms and conditions of the Plan and the Performance Restricted Stock Unit Agreement attached as Exhibit A (the “Agreement”), both of which are incorporated into this Grant Notice by reference.
Participant:
[__________]
Grant Date:
July 28, 2020
Performance Period:
July 1, 2020 through June 30, 2023
Target Number of PSUs:
[__________]
By Participant’s signature below, Participant agrees to be bound by the terms of this Grant Notice, the Plan and the Agreement. Participant has reviewed the Plan, this Grant Notice and the Agreement in their entirety, has had an opportunity to obtain the advice of counsel prior to executing this Grant Notice and fully understands all provisions of the Plan, this Grant Notice and the Agreement. Participant hereby agrees to accept as binding, conclusive and final all decisions or interpretations of the Administrator upon any questions arising under the Plan, this Grant Notice or the Agreement.
CENTENNIAL RESOURCE DEVELOPMENT, INC.
 
PARTICIPANT
By:
 
 
 
Name:
 
 
[Participant Name]
Title:
 
 
 



Exhibit A

PERFORMANCE RESTRICTED STOCK UNIT AGREEMENT
Capitalized terms not specifically defined in this Agreement have the meanings specified in the Grant Notice or, if not defined in the Grant Notice, in the Plan.
ARTICLE I.
GENERAL

1.1    Award of PSUs and Dividend Equivalents.
(a)    The Company has granted the PSUs to Participant effective as of the grant date set forth in the Grant Notice (the “Grant Date”). Each PSU represents the right to receive an amount of cash as set forth in this Agreement. Participant will have no right to receive any Shares in respect to of this Award at any time or any cash in respect of this Award until the time (if ever) the PSUs have vested.
(b)    The Company hereby grants to Participant, with respect to each PSU, a Dividend Equivalent for ordinary cash dividends paid to substantially all holders of outstanding Shares with a record date after the Grant Date and prior to the date the applicable PSU is settled, forfeited or otherwise expires. Each Dividend Equivalent entitles Participant to receive in cash (without interest) the amount of any such ordinary cash dividends paid on a single Share. The Company will establish a separate Dividend Equivalent bookkeeping account (a “Dividend Equivalent Account”) for each Dividend Equivalent and credit the Dividend Equivalent Account (without interest) on the applicable dividend payment date with the amount of any such cash paid.
1.2    Incorporation of Terms of Plan. The PSUs and Dividend Equivalents are subject to the terms and conditions set forth in this Agreement and the Plan, which is incorporated herein by reference. In the event of any inconsistency between the Plan and this Agreement, the terms of the Plan will control. This Award of PSUs shall not count against the Overall Share Limit set forth in the Plan.
1.3    Unsecured Promise. The PSUs and Dividend Equivalents will at all times prior to settlement represent an unsecured Company obligation payable only from the Company’s general assets.
ARTICLE II.
VESTING; FORFEITURE AND SETTLEMENT
2.1    Vesting; Forfeiture.
(a)    The PSUs will be earned based on the Company’s achievement of the performance conditions set forth in Appendix A and, to the extent earned, the PSUs will vest in accordance with the schedule and terms set forth in Section 2.1(b). Any fraction of a PSU that would otherwise be vested will be rounded to the nearest whole PSU. Any PSUs that are not earned in accordance with the performance conditions set forth in Appendix A will immediately and automatically be cancelled and forfeited without consideration as of the date of determination. In the event of Participant’s Termination of Service for any reason, all unvested PSUs will immediately and automatically be cancelled and forfeited, except as otherwise determined by the Administrator or provided in a binding written agreement between Participant and the Company. Dividend Equivalents (including any Dividend Equivalent Account balance) will vest or be forfeited, as applicable, upon the vesting or forfeiture of the PSU with respect to which the Dividend Equivalent (including the Dividend Equivalent Account) relates.
(b)    The PSUs will be earned, if at all, at a level of between 50% and 200% of the Target Number of PSUs specified in the Grant Notice (the “Target Number of PSUs”) based on the Company’s achievement of the performance conditions set forth in Appendix A for the Performance Period set forth in the Grant Notice (the “Performance Period”). When practicable following the completion of the Performance Period, but in no event more than forty-five (45) days thereafter, the Administrator shall determine the extent to which the performance conditions set forth in Appendix A have been satisfied (such date of determination, the “Final Determination Date”). To the extent earned, the PSUs will vest on the Final Determination Date, subject to Participant not incurring a Termination of Service on or prior to the last day of the Performance Period.



2.2    Settlement.
(a)    PSUs and Dividend Equivalents (including any Dividend Equivalent Account balance) will be paid in cash as soon as administratively practicable after the vesting of the applicable PSU, but in no event more than thirty (30) days after the PSU’s vesting date. Notwithstanding the foregoing, the Company may delay any payment under this Agreement that the Company reasonably determines would violate Applicable Law until the earliest date the Company reasonably determines the making of the payment will not cause such a violation (in accordance with Treasury Regulation Section 1.409A-2(b)(7)(ii)), provided the Company reasonably believes the delay will not result in the imposition of excise taxes under Section 409A. The amount of cash paid with respect to each PSU will equal the average Fair Market Value of a Share over the five consecutive trading days ending on the day before the PSU’s vesting date, less applicable withholdings.
ARTICLE III.
TAXATION AND TAX WITHHOLDING
3.1    Representation. Participant represents to the Company that Participant has reviewed with Participant’s own tax advisors the tax consequences of this Award and the transactions contemplated by the Grant Notice and this Agreement. Participant is relying solely on such advisors and not on any statements or representations of the Company or any of its agents.
3.2    Tax Withholding. Participant acknowledges that Participant is ultimately liable and responsible for all taxes owed in connection with the PSUs and the Dividend Equivalents, regardless of any action the Company or any Subsidiary takes with respect to any tax withholding obligations that arise in connection with the PSUs or Dividend Equivalents. Neither the Company nor any Subsidiary makes any representation or undertaking regarding the treatment of any tax withholding in connection with the awarding, vesting or payment of the PSUs or the Dividend Equivalents. The Company and the Subsidiaries do not commit and are under no obligation to structure the PSUs or Dividend Equivalents to reduce or eliminate Participant’s tax liability.
ARTICLE IV.
OTHER PROVISIONS
4.1    Adjustments. Participant acknowledges that the PSUs and the Dividend Equivalents are subject to adjustment, modification and termination in certain events as provided in this Agreement and the Plan.
4.2    Notices. Any notice to be given under the terms of this Agreement to the Company must be in writing and addressed to the Company in care of the Company’s Secretary at the Company’s principal office or the Secretary’s then-current email address or facsimile number. Any notice to be given under the terms of this Agreement to Participant must be in writing and addressed to Participant at Participant’s last known mailing address, email address or facsimile number in the Company’s personnel files. By a notice given pursuant to this Section, either party may designate a different address for notices to be given to that party. Any notice will be deemed duly given when actually received, when sent by email, when sent by certified mail (return receipt requested) and deposited with postage prepaid in a post office or branch post office regularly maintained by the United States Postal Service, when delivered by a nationally recognized express shipping company or upon receipt of a facsimile transmission confirmation.
4.3    Titles. Titles are provided herein for convenience only and are not to serve as a basis for interpretation or construction of this Agreement.
4.4    Conformity to Securities Laws. Participant acknowledges that the Plan, the Grant Notice and this Agreement are intended to conform to the extent necessary with all Applicable Laws and, to the extent Applicable Laws permit, will be deemed amended as necessary to conform to Applicable Laws.
4.5    Successors and Assigns. The Company may assign any of its rights under this Agreement to single or multiple assignees, and this Agreement will inure to the benefit of the successors and assigns of the Company.



Subject to the restrictions on transfer set forth in the Plan, this Agreement will be binding upon and inure to the benefit of the heirs, legatees, legal representatives, successors and assigns of the parties hereto.
4.6    Limitations Applicable to Section 16 Persons. Notwithstanding any other provision of the Plan or this Agreement, if Participant is subject to Section 16 of the Exchange Act, the Plan, the Grant Notice, this Agreement, the PSUs and the Dividend Equivalents will be subject to any additional limitations set forth in any applicable exemptive rule under Section 16 of the Exchange Act (including any amendment to Rule 16b-3) that are requirements for the application of such exemptive rule. To the extent Applicable Laws permit, this Agreement will be deemed amended as necessary to conform to such applicable exemptive rule.
4.7    Entire Agreement. The Plan, the Grant Notice and this Agreement (including any exhibit hereto) constitute the entire agreement of the parties and supersede in their entirety all prior undertakings and agreements of the Company and Participant with respect to the subject matter hereof.
4.8    Agreement Severable. In the event that any provision of the Grant Notice or this Agreement is held illegal or invalid, the provision will be severable from, and the illegality or invalidity of the provision will not be construed to have any effect on, the remaining provisions of the Grant Notice or this Agreement.
4.9    Limitation on Participant’s Rights. Participation in the Plan confers no rights or interests other than as herein provided. This Agreement creates only a contractual obligation on the part of the Company as to amounts payable and may not be construed as creating a trust. Neither the Plan nor any underlying program, in and of itself, has any assets. Participant will have only the rights of a general unsecured creditor of the Company with respect to amounts credited and benefits payable, if any, with respect to the PSUs and Dividend Equivalents, and rights no greater than the right to receive cash as a general unsecured creditor with respect to the PSUs and Dividend Equivalents, as and when settled pursuant to the terms of this Agreement. Nothing in this Agreement gives the Participant any rights in, to or with respect to any Shares or any other rights, other than the right to receive the cash payment described in Section 2.2.
4.10    Not a Contract of Employment. Nothing in the Plan, the Grant Notice or this Agreement confers upon Participant any right to continue in the employ or service of the Company or any Subsidiary or interferes with or restricts in any way the rights of the Company and its Subsidiaries, which rights are hereby expressly reserved, to discharge or terminate the services of Participant at any time for any reason whatsoever, with or without Cause, except to the extent expressly provided otherwise in a written agreement between the Company or a Subsidiary and Participant.
4.11    Counterparts. The Grant Notice may be executed in one or more counterparts, including by way of any electronic signature, subject to Applicable Law, each of which will be deemed an original and all of which together will constitute one instrument.
* * * * *




Appendix A

Performance Goals
The performance measure for the PSU award is the Company’s total shareholder return (“TSR”) compared to the TSR of a group of peer companies. TSR combines share price appreciation and dividends paid to show the total return to the shareholder. The absolute size of the TSR will vary with the stock market, but the relative position to Company’s peers over the Performance Period is the performance metric for this Award.
TSR will be the sum of the Company’s ending stock price plus dividends over the Performance Period divided by the Company’s beginning stock price. Both the beginning and ending stock prices will be calculated using the average closing price during the last 20 trading days prior to and including the calculation date. This calculation is used instead of the actual closing price on the given date to smooth volatility in the stock price and avoid single-day fluctuations.

TSR =         ending stock price + all dividends with a record date during the Performance Period
beginning stock price

Peer Group
The following companies are included in the Company’s peer group for purposes of this Award:

Callon Petroleum Company
Parsley Energy, Inc.
Cimarex Energy Co.
PDC Energy, Inc.
Laredo Petroleum, Inc.
QEP Resources, Inc.
Matador Resources Company
SM Energy Company
Oasis Petroleum Inc.
WPX Energy, Inc.

Should a peer company cease to exist as a separate publicly traded company during the Performance Period due to bankruptcy, it will nonetheless remain as a member of the Company’s peer group for purposes of the payout calculation described below and the Company shall be ranked higher than such peer company for purposes of the payout calculation. Should a peer company cease to exist as a separate publicly traded company during the Performance Period due to a merger, acquisition or other similar transaction, it will be automatically removed from the peer group list and the number of PSUs earned will be determined based on the Company’s percentile rank among the resulting peer group.

Payout Calculation
At the end of the Performance Period, the number of PSUs earned will be determined based on the Company’s TSR relative to the Company’s peer group over the Performance Period. The Company’s TSR is ranked among the peers and the percentile rank is calculated, based on the Company’s position in the ranking, as the percentage of members of the peer group (including the Company and as the peer group is constituted on the final day of the Performance Period) with a ranking that is greater than or equal to the Company’s ranking (i.e. with a TSR that is less than or equal to the Company’s TSR). The payout scale is detailed in the following table.



Relative TSR Performance Plan
Performance
Rank
TSR Percentile
Ranking
Payout as % of
Target Number of PSUs
1
100%
200%
2
90%
180%
3
80%
160%
4
70%
140%
5
60%
120%
6
50%
100%
7
40%
75%
8
30%
50%
9
20%
0%
10
10%
0%
11
0%
0%

The number of PSUs earned will be determined based on the TSR Percentile Ranking, with linear interpolation between any specified TSR Percentile Ranking set forth in the table above. Notwithstanding the foregoing, if the Company’s TSR is less than or equal to one (1.0), the number of PSUs shall not be greater than 100% of the Target Number of PSUs (i.e., the payout shall not be greater than 100%).

The actual payout of the PSUs, if any, at the end of the Performance Period will be made as provided under the Performance Restricted Stock Unit Agreement to which this Appendix A is attached.

Adjustments for Extraordinary Events
Notwithstanding the foregoing, if the Administrator determines that due to a reduction in the size of the peer group or other unusual, extraordinary or nonrecurring transactions or events materially affecting the Award, an adjustment in the peer group, the payment schedule and/or other terms of the Award is necessary or appropriate to avoid the dilution or enlargement of the benefits or potential benefits intended to be made available under the Award, the Administrator may adjust the peer group (including by removing constituent companies, substituting new constituent companies for existing constituent companies or selecting new constituent companies to replace withdrawn companies), the payment schedule and/or such other terms of the Award in such a manner as the Administrator determines in good faith to be equitable to reflect such transactions or events.


* * * * *




EXHIBIT 10.8

CENTENNIAL RESOURCE DEVELOPMENT, INC.
2016 LONG TERM INCENTIVE PLAN
CASH-SETTLED RESTRICTED STOCK UNIT GRANT NOTICE
Capitalized terms not specifically defined in this Cash-Settled Restricted Stock Unit Grant Notice (the “Grant Notice”) have the meanings given to them in the 2016 Long Term Incentive Plan (as amended and/or restated from time to time, the “Plan”) of Centennial Resource Development, Inc. (the “Company”).
The Company has granted to the participant listed below (“Participant”) the Restricted Stock Units described in this Grant Notice (the “RSUs”), subject to the terms and conditions of the Plan and the Restricted Stock Unit Agreement attached as Exhibit A (the “Agreement”), both of which are incorporated into this Grant Notice by reference.
Participant:
[__________]
Grant Date:
[__________]
Number of RSUs:
[__________]
Vesting Commencement Date:
[__________]
Vesting Schedule:
[__________]

By Participant’s signature below, Participant agrees to be bound by the terms of this Grant Notice, the Plan and the Agreement. Participant has reviewed the Plan, this Grant Notice and the Agreement in their entirety, has had an opportunity to obtain the advice of counsel prior to executing this Grant Notice and fully understands all provisions of the Plan, this Grant Notice and the Agreement. Participant hereby agrees to accept as binding, conclusive and final all decisions or interpretations of the Administrator upon any questions arising under the Plan, this Grant Notice or the Agreement.
CENTENNIAL RESOURCE DEVELOPMENT, INC.
 
PARTICIPANT
By:
 
 
 
Name:
 
 
[Participant Name]
Title:
 
 
 




Exhibit A



RESTRICTED STOCK UNIT AGREEMENT
ARTICLE I.
GENERAL

1.1     Award of RSUs and Dividend Equivalents

(a)The Company has granted the RSUs to Participant effective as of the grant date set forth in the Grant Notice (the “Grant Date”). Each RSU represents the right to receive an amount of cash as set forth in this Agreement. Participant will have no right to receive any Shares in respect of this Award at any time or any cash in respect of this Award until the time (if ever) the RSUs have vested.

(b)The Company hereby grants to Participant, with respect to each RSU, a Dividend Equivalent for ordinary cash dividends paid to substantially all holders of outstanding Shares with a record date after the Grant Date and prior to the date the applicable RSU is settled, forfeited or otherwise expires. Each Dividend Equivalent entitles Participant to receive in cash (without interest) the amount of any such ordinary cash dividends paid on a single Share. The Company will establish a separate Dividend Equivalent bookkeeping account (a “Dividend Equivalent Account”) for each Dividend Equivalent and credit the Dividend Equivalent Account (without interest) on the applicable dividend payment date with the amount of any such cash paid.

1.2     Incorporation of Terms of Plan. The RSUs are subject to the terms and conditions set forth in this Agreement and the Plan, which is incorporated herein by reference. In the event of any inconsistency between the Plan and this Agreement, the terms of the Plan will control. This Award of RSUs shall not count against the Overall Share Limit set forth in the Plan.

1.3     Unsecured Promise. The RSUs and Dividend Equivalents will at all times prior to settlement represent an unsecured Company obligation payable only from the Company’s general assets.

1.4     Defined Terms. Wherever the following terms are used in this Agreement, they shall have the meanings specified below, unless the context clearly indicates otherwise. Capitalized terms not specifically defined in this Agreement have the meanings specified in the Grant Notice or, if not defined in the Grant Notice, in the Plan.

(a)“Change in Control Announcement” means a public announcement by the Company regarding the execution of a Definitive CIC Agreement.

(b)“Definitive CIC Agreement” means a definitive written agreement for one or more transactions, the consummation of which will result in a Change in Control.

(c)“Maximum Return Amount” means 400% of the Fair Market Value of a Share on the Grant Date.

(d)“Maximum Return Event” means the first date on or following the first anniversary of the Vesting Commencement Date on which the Fair Market Value of a Share has exceeded the Maximum Return Amount for a total of at least 20 trading days out of any 30 consecutive trading day period.

(e)“Minimum Return Amount” means 25% of the Fair Market Value of a Share on the Grant Date.

(f)“Transaction Failure” means the termination of a Definitive CIC Agreement by the parties thereto.





ARTICLE II.
VESTING; FORFEITURE AND SETTLEMENT

2.1     Vesting; Forfeiture. The RSUs will vest according to the vesting schedule in the Grant Notice except that any fraction of an RSU that would otherwise be vested will be accumulated and will vest only when a whole RSU has accumulated. In the event of Participant’s Termination of Service for any reason, all unvested RSUs will immediately and automatically be cancelled and forfeited, except as otherwise determined by the Administrator or provided in a binding written agreement between Participant and the Company. Dividend Equivalents (including any Dividend Equivalent Account balance) will vest or be forfeited, as applicable, upon the vesting or forfeiture of the RSU with respect to which the Dividend Equivalent (including the Dividend Equivalent Account) relates.

2.2     Settlement.

(a)RSUs and Dividend Equivalents (including any Dividend Equivalent Account balance) will be paid in cash as soon as administratively practicable after the vesting of the applicable RSU, but in no event more than sixty (60) days after the RSU’s vesting date. Notwithstanding the foregoing, the Company may delay any payment under this Agreement that the Company reasonably determines would violate Applicable Law until the earliest date the Company reasonably determines the making of the payment will not cause such a violation (in accordance with Treasury Regulation Section 1.409A-2(b)(7)(ii)), provided the Company reasonably believes the delay will not result in the imposition of excise taxes under Section 409A. Subject to Section 2.2(b), the amount of cash paid with respect to each RSU will equal the greater of (i) the average Fair Market Value of a Share over the five consecutive trading days ending on the day before the vesting date or (ii) the Minimum Return Amount, in each case, less applicable withholdings; provided, however, that if such vesting took place due to the occurrence of a Maximum Return Event, then the minimum amount of cash paid with respect to each RSU will equal the Maximum Return Amount, less applicable withholdings.

(b)Notwithstanding anything to the contrary in this Agreement, the maximum amount payable with respect to an RSU awarded hereunder shall be the Maximum Return Amount plus the balance of any Dividend Equivalent Account relating to the RSU, provided that this sentence shall not apply upon or following a Change in Control Announcement unless and until a Transaction Failure has occurred.

ARTICLE III.
TAXATION AND TAX WITHHOLDING

3.1     Representation. Participant represents to the Company that Participant has reviewed with Participant’s own tax advisors the tax consequences of this Award and the transactions contemplated by the Grant Notice and this Agreement. Participant is relying solely on such advisors and not on any statements or representations of the Company or any of its agents.

3.2     Tax Withholding. Participant acknowledges that Participant is ultimately liable and responsible for all taxes owed in connection with the RSUs and the Dividend Equivalents, regardless of any action the Company or any Subsidiary takes with respect to any tax withholding obligations that arise in connection with the RSUs or Dividend Equivalents. Neither the Company nor any Subsidiary makes any representation or undertaking regarding the treatment of any tax withholding in connection with the awarding, vesting or payment of the RSUs or the Dividend Equivalents. The Company and the Subsidiaries do not commit and are under no obligation to structure the RSUs or Dividend Equivalents to reduce or eliminate Participant’s tax liability.

ARTICLE IV.
OTHER PROVISIONS

4.1     Adjustments. Participant acknowledges that the RSUs (including the Maximum Return Amount) and the Dividend Equivalents are subject to adjustment, modification and termination in certain events as provided in this Agreement and the Plan.




4.2     Notices. Any notice to be given under the terms of this Agreement to the Company must be in writing and addressed to the Company in care of the Company’s Secretary at the Company’s principal office or the Secretary’s then-current email address or facsimile number. Any notice to be given under the terms of this Agreement to Participant must be in writing and addressed to Participant at Participant’s last known mailing address, email address or facsimile number in the Company’s personnel files. By a notice given pursuant to this Section, either party may designate a different address for notices to be given to that party. Any notice will be deemed duly given when actually received, when sent by email, when sent by certified mail (return receipt requested) and deposited with postage prepaid in a post office or branch post office regularly maintained by the United States Postal Service, when delivered by a nationally recognized express shipping company or upon receipt of a facsimile transmission confirmation.

4.3     Titles. Titles are provided herein for convenience only and are not to serve as a basis for interpretation or construction of this Agreement.

4.4     Conformity to Securities Laws. Participant acknowledges that the Plan, the Grant Notice and this Agreement are intended to conform to the extent necessary with all Applicable Laws and, to the extent Applicable Laws permit, will be deemed amended as necessary to conform to Applicable Laws.

4.5     Successors and Assigns. The Company may assign any of its rights under this Agreement to single or multiple assignees, and this Agreement will inure to the benefit of the successors and assigns of the Company. Subject to the restrictions on transfer set forth in the Plan, this Agreement will be binding upon and inure to the benefit of the heirs, legatees, legal representatives, successors and assigns of the parties hereto.

4.6     Limitations Applicable to Section 16 Persons. Notwithstanding any other provision of the Plan or this Agreement, if Participant is subject to Section 16 of the Exchange Act, the Plan, the Grant Notice, this Agreement, the RSUs and the Dividend Equivalents will be subject to any additional limitations set forth in any applicable exemptive rule under Section 16 of the Exchange Act (including any amendment to Rule 16b-3) that are requirements for the application of such exemptive rule. To the extent Applicable Laws permit, this Agreement will be deemed amended as necessary to conform to such applicable exemptive rule.

4.7     Entire Agreement. The Plan, the Grant Notice and this Agreement (including any exhibit hereto) constitute the entire agreement of the parties and supersede in their entirety all prior undertakings and agreements of the Company and Participant with respect to the subject matter hereof.

4.8     Agreement Severable. In the event that any provision of the Grant Notice or this Agreement is held illegal or invalid, the provision will be severable from, and the illegality or invalidity of the provision will not be construed to have any effect on, the remaining provisions of the Grant Notice or this Agreement.

4.9     Limitation on Participant’s Rights. Participation in the Plan confers no rights or interests other than as herein provided. This Agreement creates only a contractual obligation on the part of the Company as to amounts payable and may not be construed as creating a trust. Neither the Plan nor any underlying program, in and of itself, has any assets. Participant will have only the rights of a general unsecured creditor of the Company with respect to amounts credited and benefits payable, if any, with respect to the RSUs and Dividend Equivalents, and rights no greater than the right to receive cash as a general unsecured creditor with respect to the RSUs and Dividend Equivalents, as and when settled pursuant to the terms of this Agreement. Nothing in this Agreement gives the Participant any rights in, to or with respect to any Shares or any other rights, other than the right to receive the cash payment described in Section 2.2.

4.10    Not a Contract of Employment. Nothing in the Plan, the Grant Notice or this Agreement confers upon Participant any right to continue in the employ or service of the Company or any Subsidiary or interferes with or restricts in any way the rights of the Company and its Subsidiaries, which rights are hereby expressly reserved, to discharge or terminate the services of Participant at any time for any reason whatsoever, with or without Cause, except to the extent expressly provided otherwise in a written agreement between the Company or a Subsidiary and Participant.



4.11    Counterparts. The Grant Notice may be executed in one or more counterparts, including by way of any electronic signature, subject to Applicable Law, each of which will be deemed an original and all of which together will constitute one instrument.
* * * * *




EXHIBIT 31.1

CERTIFICATION OF CHIEF EXECUTIVE OFFICER
PURSUANT TO RULES 13a-14(a) AND 15d-14(a)
OF THE SECURITIES EXCHANGE ACT OF 1934, AS AMENDED
I, Sean R. Smith, certify that:
1.
I have reviewed this Quarterly Report on Form 10-Q (this “report”) of Centennial Resource Development, Inc. (the “registrant”);
2.
Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3.
Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
4.
The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) for the registrant and have:
a.
Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
b.
Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
c.
Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
d.
Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and
5.
The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):
a.
All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
b.
Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.
Date: August 3, 2020
 
CENTENNIAL RESOURCE DEVELOPMENT, INC.
 
 
 
 
By:
/s/ SEAN R. SMITH
 
 
Sean R. Smith
Chief Executive Officer (Principal Executive Officer)



EXHIBIT 31.2

CERTIFICATION OF CHIEF FINANCIAL OFFICER
PURSUANT TO RULES 13a-14(a) AND 15d-14(a)
OF THE SECURITIES EXCHANGE ACT OF 1934, AS AMENDED
I, George S. Glyphis, certify that:
1.
I have reviewed this Quarterly Report on Form 10-Q (this “report”) of Centennial Resource Development, Inc. (the “registrant”);
2.
Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3.
Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
4.
The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) for the registrant and have:
a.
Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
b.
Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
c.
Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
d.
Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and
5.
The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):
a.
All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
b.
Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.
Date: August 3, 2020
 
CENTENNIAL RESOURCE DEVELOPMENT, INC.
 
 
 
 
By:
/s/ GEORGE S. GLYPHIS
 
 
George S. Glyphis
Vice President, Chief Financial Officer and Assistant Secretary (Principal Financial Officer)



EXHIBIT 32.1

CERTIFICATION PURSUANT TO
18 U.S.C. SECTION 1350,
AS ADOPTED PURSUANT TO
SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Quarterly Report on Form 10-Q for the quarter ended June 30, 2020 of Centennial Resource Development, Inc. (the “Company”), as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Sean R. Smith, Chief Executive Officer of the Company, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that:
(1) The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended; and
(2) The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.
Date: August 3, 2020
 
CENTENNIAL RESOURCE DEVELOPMENT, INC.
 
 
 
 
By:
/s/ SEAN R. SMITH
 
 
Sean R. Smith
Chief Executive Officer (Principal Executive Officer)






EXHIBIT 32.2

CERTIFICATION PURSUANT TO
18 U.S.C. SECTION 1350,
AS ADOPTED PURSUANT TO
SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Quarterly Report on Form 10-Q for the quarter ended June 30, 2020 of Centennial Resource Development, Inc. (the “Company”), as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, George S. Glyphis, Chief Financial Officer of the Company, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that:
(1) The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended; and
(2) The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.
Date: August 3, 2020
 
CENTENNIAL RESOURCE DEVELOPMENT, INC.
 
 
 
 
By:
/s/ GEORGE S. GLYPHIS
 
 
George S. Glyphis
Vice President, Chief Financial Officer and Assistant Secretary (Principal Financial Officer)