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, 2020March 31, 2021
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)
| | 47-5381253 | | | | | | |
| Delaware | | 47-5381253 |
| (State of Incorporation) | | (I.R.S. Employer Identification No.) |
1001 Seventeenth Street,, Suite 1800
Denver,, Colorado80202
(Registrant’s telephone number, including area code): (720) (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,April 30, 2021, there were 278,309,116279,204,514 shares of Class A Common Stock, par value $0.0001 per share outstanding.
TABLE OF CONTENTS
GLOSSARY OF OILUNITS OF MEASUREMENTS AND NATURAL GASINDUSTRY 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 optimizeinitiate 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.
Extension Well. A well drilled to extend the limits of a known 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.
NEOs. Named executive officers, which term refers to the principal executive officer, the principal financial officer, and the next three most highly paid executive officers of a company as of the end of the most recently completed fiscal year, based on total compensation as determined under Rule 402 of Regulation S-K.
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.
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.completion.
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, location, transportation and demand adjustments.
Unproved reserves. Reserves attributable to unproved properties with no proved reserves.
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.
GLOSSARY OF CERTAIN OTHER TERMS
The following are definitionsBusiness 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.Contents
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.
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, 20192020 (the “2019“2020 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-19Coronavirus Disease 2019 (“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;
•weather conditions in the areas where we operate;
•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 onWe caution you that these forward-looking statements. These forward-looking statements are subject to a numberall of the risks and uncertainties, most of which are difficult to predict and assumptions, includingmany of which are beyond our control, incident to the development, production, gathering and sale of oil and natural gas. These risks include, but are not limited to thosecommodity price volatility, inflation, lack of availability of drilling and production equipment and services, environmental risks, drilling and other operating risks, regulatory changes, the uncertainty inherent in estimating reserves and in projecting future rates of production, cash flow and access to capital, the timing of development expenditures and the other risks described underin “Item 1A. Risk Factors” in this Quarterly Report and in our 20192020 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
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 thatShould one or more of the risks or uncertainties described in our plans, intentions2020 Annual Report occur, or underlying assumptions prove incorrect, our actual results 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 theexpressed in any 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, all of which are expressly qualified by the statement in this section, to reflect events or circumstances after the date of this Quarterly Report.
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 | | March 31, 2021 | | December 31, 2020 |
| ASSETS | | | | ASSETS | | | |
| Current assets | | | | Current assets | |
| Cash and cash equivalents | $ | 7,214 |
| | $ | 10,223 |
| Cash and cash equivalents | $ | 10,936 | | | $ | 5,800 | |
| Accounts receivable, net | 64,095 |
| | 101,912 |
| Accounts receivable, net | 70,571 | | | 54,557 | |
| | Prepaid and other current assets | 6,319 |
| | 7,994 |
| Prepaid and other current assets | 5,502 | | | 5,229 | |
| Total current assets | 77,628 |
| | 120,129 |
| Total current assets | 87,009 | | | 65,586 | |
| Property and Equipment | | | | Property and Equipment | |
| Oil and natural gas properties, successful efforts method | | | | Oil and natural gas properties, successful efforts method | |
| Unproved properties | 1,328,022 |
| | 1,470,903 |
| Unproved properties | 1,192,712 | | | 1,209,205 |
| Proved properties | 4,270,397 |
| | 3,962,175 |
| Proved properties | 4,475,972 | | | 4,395,473 |
| Accumulated depreciation, depletion and amortization | (1,715,604 | ) | | (931,737) |
| Accumulated depreciation, depletion and amortization | (1,940,672) | | | (1,877,832) |
| Total oil and natural gas properties, net | 3,882,815 |
| | 4,501,341 |
| Total oil and natural gas properties, net | 3,728,012 | | | 3,726,846 |
| Other property and equipment, net | 13,765 |
| | 14,612 |
| Other property and equipment, net | 12,161 | | | 12,650 |
| Total property and equipment, net | 3,896,580 |
| | 4,515,953 |
| Total property and equipment, net | 3,740,173 | | | 3,739,496 | |
| Noncurrent assets | | | | Noncurrent assets | |
| Operating lease right-of-use assets | 4,801 |
| | 11,841 |
| Operating lease right-of-use assets | 2,381 | | | 3,176 | |
| | Other noncurrent assets | 41,877 |
| | 40,365 |
| Other noncurrent assets | 18,758 | | | 19,167 |
| TOTAL ASSETS | $ | 4,020,886 |
| | $ | 4,688,288 |
| TOTAL ASSETS | $ | 3,848,321 | | | $ | 3,827,425 | |
| | | | | |
| LIABILITIES AND EQUITY | | | | LIABILITIES AND EQUITY | | | |
| Current liabilities | | | | Current liabilities | |
| Accounts payable and accrued expenses | $ | 122,360 |
| | $ | 244,309 |
| Accounts payable and accrued expenses | $ | 144,958 | | | $ | 110,439 | |
| Derivative instruments | 31,740 |
| | 325 |
| |
| | Operating lease liabilities | 3,591 |
| | 9,232 |
| Operating lease liabilities | 2,697 | | | 3,155 | |
| Other current liabilities | 170 |
| | 600 |
| Other current liabilities | 46,536 | | | 18,274 | |
| Total current liabilities | 157,861 |
| | 254,466 |
| Total current liabilities | 194,191 | | | 131,868 |
| Noncurrent liabilities | | | | Noncurrent liabilities | |
| Long-term debt, net | 1,106,043 |
| | 1,057,389 |
| Long-term debt, net | 1,063,754 | | | 1,068,624 | |
| Asset retirement obligations | 18,067 |
| | 16,874 |
| Asset retirement obligations | 17,158 | | | 17,009 | |
| Deferred income taxes | 2,589 |
| | 85,504 |
| Deferred income taxes | 2,589 | | | 2,589 | |
| | Operating lease liabilities | 1,783 |
| | 3,354 |
| Operating lease liabilities | 0 | | | 422 | |
| Other noncurrent liabilities | | Other noncurrent liabilities | 11,726 | | | 2,952 | |
| Total liabilities | 1,286,343 |
| | 1,417,587 |
| Total liabilities | 1,289,418 | | | 1,223,464 |
| Commitments and contingencies (Note 11) |
|
| |
|
| |
| Commitments and contingencies (Note 10) | | Commitments and contingencies (Note 10) | 0 | | 0 |
| Shareholders’ equity | | | | 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: | | | | 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 | — |
| | — |
| |
| Class A: 290,792,727 shares issued and 279,124,752 shares outstanding at March 31, 2021 and 290,645,623 shares issued and 278,551,901 shares outstanding at December 31, 2020 | | Class A: 290,792,727 shares issued and 279,124,752 shares outstanding at March 31, 2021 and 290,645,623 shares issued and 278,551,901 shares outstanding at December 31, 2020 | 29 | | | 29 | |
| | Additional paid-in capital | 2,994,832 |
| | 2,975,756 |
| Additional paid-in capital | 2,994,020 | | | 3,004,433 | |
| Retained earnings (accumulated deficit) | (260,317 | ) | | 282,336 |
| Retained earnings (accumulated deficit) | (435,146) | | | (400,501) | |
| Total shareholders’ equity | 2,734,543 |
| | 3,258,120 |
| Total shareholders’ equity | 2,558,903 | | | 2,603,961 | |
| Noncontrolling interest | — |
| | 12,581 |
| Noncontrolling interest | 0 | | | 0 | |
| Total equity | 2,734,543 |
| | 3,270,701 |
| Total equity | 2,558,903 | | | 2,603,961 | |
| TOTAL LIABILITIES AND EQUITY | $ | 4,020,886 |
| | $ | 4,688,288 |
| TOTAL LIABILITIES AND EQUITY | $ | 3,848,321 | | | $ | 3,827,425 | |
The accompanying notes are an integral part of these unaudited consolidated financial statements.
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, | | Three Months Ended March 31, | |
| | 2020 | | 2019 | | 2020 | | 2019 | | 2021 | | 2020 | |
| Operating revenues | | | | | | | | Operating revenues | | | | |
| Oil and gas sales | $ | 90,509 |
| | $ | 244,239 |
| | $ | 283,278 |
| | $ | 458,808 |
| Oil and gas sales | $ | 192,391 | | | $ | 192,769 | | |
| Operating expenses | | | | | | | | Operating expenses | | |
| Lease operating expenses | 25,839 |
| | 34,885 |
| | 58,478 |
| | 64,747 |
| Lease operating expenses | 25,861 | | | 32,639 | | |
| Severance and ad valorem taxes | 5,696 |
| | 17,186 |
| | 22,269 |
| | 33,306 |
| Severance and ad valorem taxes | 12,583 | | | 16,573 | | |
| Gathering, processing and transportation expenses | 17,284 |
| | 16,243 |
| | 34,223 |
| | 31,267 |
| Gathering, processing and transportation expenses | 20,625 | | | 16,939 | | |
| Depreciation, depletion and amortization | 93,020 |
| | 112,114 |
| | 194,278 |
| | 208,672 |
| Depreciation, depletion and amortization | 63,783 | | | 101,258 | | |
| Impairment and abandonment expense | 19,425 |
| | 4,418 |
| | 630,725 |
| | 35,682 |
| Impairment and abandonment expense | 9,200 | | | 611,300 | | |
| Exploration expense | 4,051 |
| | 3,861 |
| | 8,060 |
| | 6,377 |
| |
| Exploration and other expenses | | Exploration and other expenses | 1,095 | | | 4,009 | | |
| General and administrative expenses | 17,994 |
| | 18,435 |
| | 36,864 |
| | 36,553 |
| General and administrative expenses | 25,256 | | | 18,870 | | |
| Total operating expenses | 183,309 |
| | 207,142 |
| | 984,897 |
| | 416,604 |
| Total operating expenses | 158,403 | | | 801,588 | | |
| Net gain (loss) on sale of long-lived assets | (2 | ) | | 9 |
| | 243 |
| | 7 |
| Net gain (loss) on sale of long-lived assets | 44 | | | 245 | | |
| Income (loss) from operations | (92,802 | ) | | 37,106 |
| | (701,376 | ) | | 42,211 |
| Income (loss) from operations | 34,032 | | | (608,574) | | |
| | | | | | | | | | |
| Other income (expense) | | | | | | | | Other income (expense) | | |
| Interest expense | (17,371 | ) | | (14,437 | ) | | (33,792 | ) | | (24,597 | ) | Interest expense | (17,485) | | | (16,421) | | |
| Gain on exchange of debt | 143,443 |
| | — |
| | 143,443 |
| | — |
| |
| | Net gain (loss) on derivative instruments | (29,857 | ) | | 2,128 |
| | (38,362 | ) | | (3,743 | ) | Net gain (loss) on derivative instruments | (51,199) | | | (8,505) | | |
| Other income (expense) | 1 |
| | 133 |
| | (52 | ) | | 259 |
| Other income (expense) | 7 | | | (53) | | |
| Total other income (expense) | 96,216 |
| | (12,176 | ) | | 71,237 |
| | (28,081 | ) | Total other income (expense) | (68,677) | | | (24,979) | | |
| | | | | | | | | | | | | |
| Income (loss) before income taxes | 3,414 |
| | 24,930 |
| | (630,139 | ) | | 14,130 |
| Income (loss) before income taxes | (34,645) | | | (633,553) | | |
| Income tax (expense) benefit | 1,916 |
| | (5,928 | ) | | 85,124 |
| | (3,665 | ) | Income tax (expense) benefit | 0 | | | 83,208 | | |
| Net income (loss) | 5,330 |
| | 19,002 |
| | (545,015 | ) | | 10,465 |
| Net income (loss) | (34,645) | | | (550,345) | | |
| Less: Net (income) loss attributable to noncontrolling interest | — |
| | (1,125 | ) | | 2,362 |
| | (700 | ) | Less: Net (income) loss attributable to noncontrolling interest | 0 | | | 2,362 | | |
| Net income (loss) attributable to Class A Common Stock | $ | 5,330 |
| | $ | 17,877 |
| | $ | (542,653 | ) | | $ | 9,765 |
| Net income (loss) attributable to Class A Common Stock | $ | (34,645) | | | $ | (547,983) | | |
| | | | | |
|
| |
|
| | | | | |
| Income (loss) per share of Class A Common Stock: | | | | | | | | Income (loss) per share of Class A Common Stock: | | |
| Basic | $ | 0.02 |
| | $ | 0.07 |
| | $ | (1.96 | ) | | $ | 0.04 |
| Basic | $ | (0.12) | | | $ | (1.99) | | |
| Diluted | $ | 0.02 |
| | $ | 0.07 |
| | $ | (1.96 | ) | | $ | 0.04 |
| Diluted | $ | (0.12) | | | $ | (1.99) | | |
The accompanying notes are an integral part of these unaudited consolidated financial statements.
CENTENNIAL RESOURCE DEVELOPMENT, INC.
CONSOLIDATED STATEMENTS OF CASH FLOWS (unaudited)
(in thousands)
| | | | Six Months Ended June 30, | | Three Months Ended March 31, |
| | 2020 |
| 2019 | | 2021 |
| 2020 |
| Cash flows from operating activities: | | | | Cash flows from operating activities: | | | |
| Net income (loss) | $ | (545,015 | ) | | $ | 10,465 |
| Net income (loss) | $ | (34,645) | | | $ | (550,345) | |
| Adjustments to reconcile net income to net cash provided by operating activities: | | | | |
| Adjustments to reconcile net income (loss) to net cash provided by operating activities: | | Adjustments to reconcile net income (loss) to net cash provided by operating activities: | |
| Depreciation, depletion and amortization | 194,278 |
| | 208,672 |
| Depreciation, depletion and amortization | 63,783 | | | 101,258 | |
| Stock-based compensation expense | 11,136 |
| | 13,241 |
| |
| Stock-based compensation expense - equity awards | | Stock-based compensation expense - equity awards | 4,585 | | | 6,409 | |
| Stock-based compensation expense - liability awards | | Stock-based compensation expense - liability awards | 10,414 | | | 0 | |
| Impairment and abandonment expense | 630,725 |
| | 35,682 |
| Impairment and abandonment expense | 9,200 | | | 611,300 | |
| Deferred tax expense (benefit) | (85,124 | ) | | 3,665 |
| Deferred tax expense (benefit) | 0 | | | (83,208) | |
| Net (gain) loss on sale of long-lived assets | (243 | ) | | (7 | ) | Net (gain) loss on sale of long-lived assets | (44) | | | (245) | |
| Non-cash portion of derivative (gain) loss | 31,415 |
| | 9,754 |
| Non-cash portion of derivative (gain) loss | 28,313 | | | 8,452 | |
| Amortization of debt issuance costs and discount | 2,334 |
| | 1,287 |
| Amortization of debt issuance costs and discount | 1,847 | | | 799 | |
| Gain on exchange of debt | (143,443 | ) | | — |
| |
| | Changes in operating assets and liabilities: | | | | Changes in operating assets and liabilities: | |
| (Increase) decrease in accounts receivable | 36,065 |
| | (22,751 | ) | (Increase) decrease in accounts receivable | (14,997) | | | 41,026 | |
| (Increase) decrease in prepaid and other assets | 41 |
| | (154 | ) | (Increase) decrease in prepaid and other assets | (264) | | | (263) | |
| Increase (decrease) in accounts payable and other liabilities | (47,666 | ) | | 20,340 |
| Increase (decrease) in accounts payable and other liabilities | 4,154 | | | (34,365) | |
| Net cash provided by operating activities | 84,503 |
| | 280,194 |
| Net cash provided by operating activities | 72,346 | | | 100,818 | |
| Cash flows from investing activities: | | | | Cash flows from investing activities: | | | |
| Acquisition of oil and natural gas properties | (6,113 | ) | | (42,264 | ) | Acquisition of oil and natural gas properties | (433) | | | (5,795) | |
| Drilling and development capital expenditures | (271,389 | ) | | (437,912 | ) | Drilling and development capital expenditures | (46,152) | | | (161,895) | |
| Purchases of other property and equipment | (811 | ) | | (4,263 | ) | Purchases of other property and equipment | (181) | | | (486) | |
| Proceeds from sales of oil and natural gas properties | 1,263 |
| | 25,919 |
| Proceeds from sales of oil and natural gas properties | 168 | | | 1,200 | |
| Net cash used in investing activities | (277,050 | ) | | (458,520 | ) | Net cash used in investing activities | (46,598) | | | (166,976) | |
| Cash flows from financing activities: | | | | Cash flows from financing activities: | | | |
| | Proceeds from borrowings under revolving credit facility | 385,000 |
| | 155,000 |
| Proceeds from borrowings under revolving credit facility | 70,000 | | | 195,000 | |
| Repayment of borrowings under revolving credit facility | (190,000 | ) | | (455,000 | ) | Repayment of borrowings under revolving credit facility | (240,000) | | | (135,000) | |
| Proceeds from issuance of senior notes | — |
| | 496,175 |
| |
| Debt exchange and debt issuance costs | (5,141 | ) | | (7,200 | ) | |
| Proceeds from issuance of convertible senior notes | | Proceeds from issuance of convertible senior notes | 170,000 | | | 0 | |
| Debt issuance costs | | Debt issuance costs | (5,444) | | | 0 | |
| Premiums paid on capped call transactions | | Premiums paid on capped call transactions | (14,688) | | | 0 | |
| | Restricted stock used for tax withholdings | (301 | ) | | (332 | ) | Restricted stock used for tax withholdings | (477) | | | (208) | |
| Net cash provided by financing activities | 189,558 |
| | 188,643 |
| |
| Net cash (used in) provided by financing activities | | Net cash (used in) provided by financing activities | (20,609) | | | 59,792 | |
| Net increase (decrease) in cash, cash equivalents and restricted cash | (2,989 | ) | | 10,317 |
| Net increase (decrease) in cash, cash equivalents and restricted cash | 5,139 | | | (6,366) | |
| Cash, cash equivalents and restricted cash, beginning of period | 15,543 |
| | 21,422 |
| Cash, cash equivalents and restricted cash, beginning of period | 8,339 | | | 15,543 | |
| Cash, cash equivalents and restricted cash, end of period | $ | 12,554 |
| | $ | 31,739 |
| Cash, cash equivalents and restricted cash, end of period | $ | 13,478 | | | $ | 9,177 | |
The accompanying notes are an integral part of these unaudited consolidated financial statements.
CENTENNIAL RESOURCE DEVELOPMENT, INC.
CONSOLIDATED STATEMENTS OF CASH FLOWS (unaudited) (continued)
(in thousands)
| | | | | | | | | | | |
| Three Months Ended March 31, |
| 2021 |
| 2020 |
| Supplemental cash flow information | | | |
| Cash paid for interest | $ | 11,272 | | | $ | 12,977 | |
| | | |
| Supplemental non-cash activity | | | |
| Accrued capital expenditures included in accounts payable and accrued expenses | $ | 50,333 | | | $ | 108,282 | |
| Asset retirement obligations incurred, including revisions to estimates | 24 | | | 413 | |
| | | |
| | | |
| | | |
| | | |
|
| | | | | | | |
| | 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 Statementsconsolidated statements of Cash Flowscash 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 |
|
| | | | | | | | | | | |
| Three Months Ended March 31, |
| 2021 | | 2020 |
| Cash and cash equivalents | $ | 10,936 | | | $ | 3,841 | |
Restricted cash(1) | 2,542 | | | 5,336 | |
| Total cash, cash equivalents and restricted cash | $ | 13,478 | | | $ | 9,177 | |
| |
(1)(1) Included in Prepaid and other current assets and Other noncurrent assets line items in the consolidated balance sheets. | 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.
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 |
|
CENTENNIAL RESOURCE DEVELOPMENT, INC.
CONSOLIDATED STATEMENTS OF SHAREHOLDERS’ EQUITY (unaudited) (continued)
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | 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 |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Common Stock | | | | | | | | | | |
| Class A | | Class C | | Additional Paid-In Capital | | Retained Earnings (Accumulated Deficit) | | Total Shareholders’ Equity | | Non-controlling Interest | | Total Equity |
| Shares | | Amount | | Shares | | Amount | | | | | |
| Balance at December 31, 2020 | 290,646 | | | $ | 29 | | | 0 | | | $ | 0 | | | $ | 3,004,433 | | | $ | (400,501) | | | $ | 2,603,961 | | | $ | 0 | | | $ | 2,603,961 | |
| | | | | | | | | | | | | | | | | |
| Restricted stock forfeited | (1) | | | — | | | — | | | — | | | — | | | — | | | — | | | — | | | — | |
| Restricted stock used for tax withholding | (128) | | | — | | | — | | | — | | | (477) | | | — | | | (477) | | | — | | | (477) | |
| Issuance of Class A common stock under Employee Stock Purchase Plan | 276 | | | — | | | — | | | — | | | 167 | | | — | | | 167 | | | — | | | 167 | |
| Stock-based compensation - equity awards | — | | | — | | | — | | | — | | | 4,585 | | | — | | | 4,585 | | | — | | | 4,585 | |
| Capped call premiums | — | | | — | | | — | | | — | | | (14,688) | | | — | | | (14,688) | | | — | | | (14,688) | |
| Net income (loss) | — | | | — | | | — | | | — | | | — | | | (34,645) | | | (34,645) | | | — | | | (34,645) | |
| Balance at March 31, 2021 | 290,793 | | | 29 | | | 0 | | | 0 | | | 2,994,020 | | | (435,146) | | | 2,558,903 | | | 0 | | | 2,558,903 | |
| | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | |
| | | | | | | | | | | | | |
| | | | | | | | | | | | |
| Balance at December 31, 2019 | 280,650 | | | $ | 28 | | | 1,034 | | | $ | 0 | | | $ | 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 - equity awards | — | | | — | | | — | | | — | | | 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 | | | 0 | | | 2,982,187 | | | (265,647) | | | 2,716,568 | | | 10,219 | | | 2,726,787 | |
| | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | |
The accompanying notes are an integral part of these unaudited consolidated financial statements.
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, 20192020 (the “2019“2020 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 20192020 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 DecemberMarch 31, 2019,2020 the noncontrolling interest ownership of CRP was 0.4%.
On April 2, 2020, the legacy owners of CRP converted but was subsequently reduced to 0 as all of their remaining1,034,119 CRP Common Units (and corresponding shares of the Company’s Class C Common Stock)common stock) were converted into shares of the Company’s Class A Common Stockcommon stock (the “Conversion”“Common Stock”), which eliminated the noncontrolling interest ownership in CRP. As a result, and CRP washas since been a wholly-owned subsidiary of Centennial Resource Development, Inc. for the three month period ended June 30, 2020. NaN 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.Centennial.
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. Additionally, the prices received for oil, natural gas and NGL production can heavily influence the Company’s assumptions, judgments and estimates and continued volatility of oil and gas prices could have a significant impact on the Company’s estimates.
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;derivative valuations; 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
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.
CENTENNIAL RESOURCE DEVELOPMENT, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
The Company has 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 both the three and six months ended June 30,March 31, 2021 and 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.
RisksRecently Issued or Adopted Accounting Standards
In August 2020, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2020-06, Debt—Debt with Conversion and Uncertainties
Other Options and Derivatives and Hedging— Contracts in Entity’s Own Equity (“ASU 2020-06”), which updates the accounting requirements for convertible debt instruments and contracts in an entity’s own equity under FASB’s Accounting Standard Codification (“ASC”) Topic 470, Debt, ASC Topic 815, Derivatives and Hedging, and applicable earnings-per-share guidance. The prices receivedamendments in ASU 2020-06 are intended to simplify the accounting for oil, natural gasconvertible instruments by removing certain separation models in the existing debt guidance allowing convertible debt to be recorded as a single liability measured at its amortized cost. Additionally, the amendments remove certain conditions and NGL production heavily influenceclarify the Company’s revenue, profitability, liquidity, accessscope of and certain requirements pertaining to capital, future rate of growthderivative scope exception evaluations over such contracts and carrying value of its properties. Oil, natural gasinstruments. ASU 2020-06 requires retrospective application 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.is effective for public entities for fiscal years beginning after December 15, 2021, including interim periods within those fiscal years, with early adoption permitted after December 15, 2020. The Company generally funds its operationshas adopted this guidance as of January 1, 2021, 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 effectthere was no impact 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, andpreviously reported amounts as a result the distribution of the Deposit is under ongoing litigation between the Company and the purchaser.adoption. Refer to
Note 3—Long-Term Debt for additional information regarding its convertible debt instruments.
Note 2—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 |
|
| | | | | | | | | | | |
| (in thousands) | March 31, 2021 | | December 31, 2020 |
| Accrued oil and gas sales receivable, net | $ | 54,042 | | | $ | 41,670 | |
| Joint interest billings, net | 15,218 | | | 12,770 | |
| Other | 1,311 | | | 117 | |
| Accounts receivable, net | $ | 70,571 | | | $ | 54,557 | |
| | | | | | | | | | | |
| (in thousands) | March 31, 2021 | | December 31, 2020 |
| Accounts payable | $ | 19,124 | | | $ | 5,052 | |
| Accrued capital expenditures | 38,259 | | | 21,471 | |
| Revenues payable | 32,776 | | | 42,115 | |
| Accrued interest | 19,922 | | | 15,138 | |
| Accrued derivative settlements payable | 10,411 | | | 3,488 | |
| Accrued employee compensation and benefits | 8,173 | | | 11,516 | |
| Accrued expenses and other | 16,293 | | | 11,659 | |
| Accounts payable and accrued expenses | $ | 144,958 | | | $ | 110,439 | |
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—3—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 |
|
| | | | | | | | | | | |
| (in thousands) | March 31, 2021 | | December 31, 2020 |
| Credit Facility due 2023 | $ | 160,000 | | | $ | 330,000 | |
| | | |
| 8.00% Senior Secured Notes due 2025 | 127,073 | | | 127,073 | |
| 5.375% Senior Notes due 2026 | 289,448 | | | 289,448 | |
| 6.875% Senior Notes due 2027 | 356,351 | | | 356,351 | |
| 3.25% Convertible Senior Notes due 2028 | 170,000 | | | 0 | |
| Unamortized debt issuance costs on Senior Notes | (18,561) | | | (12,790) | |
| Unamortized debt discount | (20,557) | | | (21,458) | |
| Senior Notes, net | 903,754 | | | 738,624 | |
| | | |
| Total long-term debt, net | $ | 1,063,754 | | | $ | 1,068,624 | |
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,March 31, 2021, the Company had $370.0$160.0 million in borrowings outstanding and $290.0$503.9 million in available borrowing capacity, which was net of $8.2$4.3 million in letters of credit outstanding and the availability blocker of $31.8 million. This availability blocker was subsequently removed in connection with the Senior Secured Note redemption; refer to Note 13—Subsequent Events for additional information regarding this redemption.
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 wasare currently 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 2 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. In connection with the Credit Agreement’s spring 2021 semi-annual borrowing base redetermination, the borrowing base and amount of elected commitments were reaffirmed at $700.0 million.
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,March 31, 2021, 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
CENTENNIAL RESOURCE DEVELOPMENT, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
points as of June 30, 2020,March 31, 2021, 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 agreementCredit Agreement and non-cash derivative liabilities), of not less than 1.0 to 1.0;
CENTENNIAL RESOURCE DEVELOPMENT, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
(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 amendments to the 2020 Amendments,Credit Facility, the leverage ratio iswas suspended until March 31, 2022, at which time, the ratio may not exceed 5.005.0 to 1.00,1.0, 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 applicable financial ratios described above as of June 30, 2020March 31, 2021 and through the filing of this Quarterly Report.
Convertible Senior Notes
On March 19, 2021, CRP issued $150.0 million in aggregate principal amount of 3.25% senior unsecured convertible notes due 2028 (the “Convertible Senior Notes”). On March 26, 2021, CRP issued an additional $20.0 million of Convertible Senior Notes pursuant to the exercise of the underwriters’ over-allotment option to purchase additional Convertible Senior Notes. These issuances resulted in aggregate net proceeds to CRP of $163.7 million, after deducting debt issuance costs of $6.3 million. Interest is payable on the Convertible Senior Notes semi-annually in arrears on each April 1 and October 1, commencing on October 1, 2021.
The Convertible Senior Notes are fully and unconditionally guaranteed on a senior unsecured basis by the Company and each of CRP’s current subsidiaries.
The Convertible Senior Notes will mature on April 1, 2028 unless earlier repurchased, redeemed or converted. Before January 3, 2028, noteholders have the right to convert their Convertible Senior Notes (i) upon the occurrence of certain events, (ii) if the Company’s share price exceeds 130% of the conversion price for any 20 trading days during the last 30 consecutive trading days of a calendar quarter, after June 30, 2021, or (iii) if the trading price per $1,000 principal amount of the notes is less than 98% of the Company’s share price multiplied by the conversion rate, for a 10 consecutive trading day period. In addition, after January 2, 2028, noteholders may convert their Convertible Senior Notes at any time at their election through the second scheduled trading day immediately before the April 1, 2028 maturity date.
CRP can settle conversions by paying or delivering, as applicable, cash, shares of Common Stock, or a combination of cash and shares of Common Stock, at CRP’s election. The initial conversion rate is 159.2610 shares of Common Stock per $1,000 principal amount of Convertible Senior Notes, which represents an initial conversion price of approximately $6.28 per share of Common Stock. The conversion rate and conversion price are subject to customary adjustments upon the occurrence of certain events (as defined in the indenture) which, in certain circumstances, will increase the conversion rate for a specified period of time. In the context of this issuance, we refer to the notes as convertible in accordance with ASC 470 - Debt. However, per the terms of the Convertible Senior Notes’ indenture, the Convertible Senior Notes were issued by CRP and are exchangeable into shares of Centennial Resource Development, Inc’s Common Stock.
CRP has the option to redeem, in whole or in part, all of the Convertible Senior Notes at any time on or after April 7, 2025, at a redemption price equal to 100% of the principal amount, plus accrued and unpaid interest to the date of redemption, but only if the last reported sale price per share of Common Stock exceeds 130% of the conversion price (i) for any 20 trading days during the 30 consecutive trading days ending on the day immediately before the date CRP sends the related redemption notice; and (ii) also on the trading day immediately before the date CRP sends such notice.
If certain corporate events occur, including certain business combination transactions involving the Company or CRP or a stock de-listing with respect to the Common Stock, noteholders may require CRP to repurchase their Convertible Senior Notes at a cash repurchase price equal to the principal amount of the Convertible Senior Notes to be repurchased, plus accrued and unpaid interest to the repurchase date.
Upon an Event of Default (as defined in the indenture governing the Convertible Senior Notes), the trustee or the holders of at least 25% of the aggregate principal amount of then outstanding Convertible Senior Notes may declare the Convertible Senior Notes immediately due and payable. In addition, a default resulting from certain events of bankruptcy or insolvency with respect to the Company, CRP or any of the subsidiary guarantors will automatically cause all outstanding Convertible Senior Notes to become due and payable.
CENTENNIAL RESOURCE DEVELOPMENT, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
At issuance, the Company recorded a liability equal to the face value the Convertible Senior Notes, net of unamortized debt issuance costs in the line items Long-term debt, net in the consolidated balance sheets. As of March 31, 2021, the net liability recorded related to the Convertible Senior Notes was $163.7 million.
Capped Called Transactions
In connection with the issuance of the Convertible Senior Notes in March 2021, CRP entered into privately negotiated capped call spread transactions with option counterparties (the “Capped Call Transactions”). The Capped Call Transactions cover the aggregate number of shares of Common Stock that initially underlie the Convertible Senior Notes and are expected to (i) generally reduce potential dilution to the Common Stock upon a conversion of the Convertible Senior Notes, and/or (ii) offset any cash payments CRP is required to make in excess of the principal amount of the Convertible Senior Notes, subject to a cap. The Capped Call Transactions have an initial strike price of $6.28 per share of Common Stock and an initial capped price of $8.4525 per share of Common Stock, each of which are subject to certain customary adjustments upon the occurrence of certain corporate events, as defined in the capped call agreements.
The cost of the Capped Call Transactions was $14.7 million, which was funded from proceeds from the Convertible Senior Note issuance. The cost to purchase the Capped Call Transactions was recorded to additional paid-in capital in the consolidated balances sheets and will not be subject to remeasurement each reporting period.
Senior Unsecured NoteNotes 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 The Company’s Debt Exchange was accounted for as an extinguishment of debt in accordance with ASC Topic 470-50,. Modifications and Extinguishments. As a result, a gain on the exchange of debt of $143.4 million was recognized in the Consolidated Statementconsolidated statement of Operations,operations during the second quarter of 2020, which consisted of the carrying values of the Senior Unsecured Notes exchanged less the aggregate principal amount of the new Senior Secured Notes issued, net of their associated debt discount of $21.0 million, (whichwhich was based on the notes’Senior Secured Notes’ estimated fair value on the exchange date).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.
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.
CENTENNIAL RESOURCE DEVELOPMENT, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
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,March 31, 2021, 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,March 31, 2021, 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, 2020March 31, 2021 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.
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.
CENTENNIAL RESOURCE DEVELOPMENT, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
Note 5—4—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 sixthree months ended June 30, 2020:March 31, 2021:
|
| | | |
| (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 |
|
| | | | | |
| (in thousands) | |
| Asset retirement obligations, beginning of period | $ | 17,009 | |
| |
| Liabilities incurred | 44 | |
| |
| Liabilities divested and settled | (129) | |
| Accretion expense | 255 | |
| Revisions to estimated cash flows | (21) | |
| Asset retirement obligations, end of period | $ | 17,158 | |
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 estimates and 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,liabilities, 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 with an offsetting charge to accretion expense, which is included within depreciation, depletion and as accretion expense.amortization.
Note 6—5—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.issuance to employees and directors. 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,March 31, 2021, the Company had 14,763,3456,601,016 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 expenseand other expenses in the Consolidated Statementsconsolidated statements of Operations.operations. The Company accounts for forfeitures of awards granted under the LTIP as they occur in determining compensation expense.
| | | | | | | | | | | | | | | |
| Three Months Ended March 31, | | |
| (in thousands) | 2021 | | 2020 | | | | |
| Equity Awards | | | | | | | |
| Restricted stock awards | $ | 3,606 | | | $ | 4,354 | | | | | |
| Stock option awards | 271 | | | 984 | | | | | |
| Performance stock units | 639 | | | 1,003 | | | | | |
Other stock-based compensation expense(1) | 69 | | | 68 | | | | | |
| Total stock-based compensation - equity awards | 4,585 | | | 6,409 | | | | | |
| | | | | | | |
| Liability Awards | | | | | | | |
| Restricted stock units | 3,308 | | | 0 | | | | | |
| Performance stock units | 7,106 | | | 0 | | | | | |
| Total stock-based compensation - liability awards | 10,414 | | | 0 | | | | | |
| | | | | | | |
| Total stock-based compensation expense | $ | 14,999 | | | $ | 6,409 | | | | | |
(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 March 31, 2021, the Company had 1,561,164 shares of Common Stock available for future issuance.
CENTENNIAL RESOURCE DEVELOPMENT, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
The following table summarizes stock-based compensation expense recognized forCompany has restricted stock awards, stock options and performance stock units (“PSUs”) outstanding that were granted under the periods presented:LTIP as discussed below. Each award has service-based and, in the case of the PSUs, market-based vesting requirements, and are expected to be settled in shares of Common Stock upon vesting. As a result, these awards are classified as equity-based awards in accordance with ASC Topic 718, |
| | | | | | | | | | | | | | | |
| | 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) Compensation-Stock Compensation (“ASC 718”).
| 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 sixthree months ended June 30, 2020:March 31, 2021:
|
| | | | | | |
| | 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 |
|
| | | | | | | | | | | |
| Awards | | Weighted Average Grant-Date Fair Value |
| Unvested balance as of December 31, 2020 | 12,093,723 | | | $ | 2.33 | |
| Granted | 0 | | | 0 | |
| Vested | (424,290) | | | 6.21 | |
| Forfeited | (1,457) | | | 14.28 | |
| Unvested balance as of March 31, 2021 | 11,667,976 | | | 2.18 | |
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 thethese service-based restricted stock awards is based on the closing market price of the Company’s Class A common stockCommon Stock on the grant date, and such costs are recognized ratably over the applicable vesting period. The weighted average grant-date fair value forThere were 0 restricted stock awards granted during the period was $2.53 and $12.48 per share for the sixthree months ended June 30, 2020 and 2019, respectively.March 31, 2021. The total fair value of restricted stock awards that vested during the sixthree months ended June 30,March 31, 2021 and 2020 and 2019 was $4.6$2.6 million and $1.5$3.8 million, respectively, and includes awards with vesting terms that were accelerated as discussed above.respectively. Unrecognized compensation cost related to restricted shares that were unvested as of June 30, 2020March 31, 2021 was $21.7$17.4 million, which the Company expects to recognize over a weighted average period of 1.91.7 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 volatilityhistorical volatilities 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.
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:three months ended March 31, 2020. NaN stock options were granted during the three months ended March 31, 2021.
| | | | | | | |
| | | Three Months Ended March 31, 2020 |
| | | |
| Weighted average grant-date fair value per share | | | $ | 2.37 | |
| Expected term (in years) | | | 6 |
| Expected stock volatility | | | 52 | % |
| Dividend yield | | | 0 | % |
| Risk-free interest rate | | | 1.7 | % |
|
| | | | | | | |
| 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 | % |
19
CENTENNIAL RESOURCE DEVELOPMENT, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
The following table provides information about stock option awards outstanding during the sixthree months ended June 30, 2020:March 31, 2021:
|
| | | | | | | | | | | | |
| | 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 | | $ | — |
|
| | | | | | | | | | | | | | | | | | | | | | | |
| Options | | Weighted Average Exercise Price | | Weighted Average Remaining Term
(in years) | | Aggregate Intrinsic Value
(in thousands) |
| Outstanding as of December 31, 2020 | 2,363,334 | | | $ | 15.07 | | | | | |
| Granted | 0 | | | 0 | | | | | |
| Exercised | 0 | | | 0 | | | | | $ | 0 | |
| Forfeited | (5,000) | | | 4.69 | | | | | |
| Expired | (15,333) | | | 18.11 | | | | | |
| Outstanding as of March 31, 2021 | 2,343,001 | | | 15.07 | | | 6.2 | | $ | 247 | |
| Exercisable as of March 31, 2021 | 2,054,477 | | | 15.83 | | | 5.9 | | $ | 1 | |
| | | | | | | |
The total fair value of stock options that vested during the sixthree months ended June 30,March 31, 2021 and 2020 and 2019 was $4.2$0.3 million and $4.1$3.5 million, respectively, and includes awards with vesting terms that were accelerated as discussed above.respectively. There were 0 stock options exercised during either the sixthree months ended June 30, 2020 or 2019.March 31, 2021 and 2020. As of June 30, 2020,March 31, 2021, there was $1.8$0.6 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 1.40.9 years.
Performance Stock Units
The Company grants performance stock units to certain executive officers that are subject to market-based vesting criteria as well as a three-year service period. Vesting at the end of the three-year service period is subject to the condition that the Company’s stock price increases by a greater percentage, or decreases by a lesser percentage, than the average percentage increase or decrease, respectively, of the stock prices of a peer group of companies. The market-based conditions must be met in order for the stock awards to vest, and it is, therefore, possible that no shares could ultimately vest. However, the Company recognizes compensation expense for the performance stock units subject to market conditions regardless of whether it becomes probable that these conditions will be met or not, and compensation expense is not reversed if vesting does not actually occur.
During the sixthree months ended June 30,March 31, 2021 and 2020, and 2019, there was no significant performance stock units activity. As of June 30, 2020,March 31, 2021, there was $3.7$1.8 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 1.0 year.
Liability Awards
The Company has restricted stock units and performance stock units that were granted under the LTIP, which will be settled in cash and are classified as liability awards in accordance with ASC 718. Compensation cost for the liability awards is based on the fair value of the units as of the balance sheet date as further discussed below, and such costs are recognized ratably over the service periods of the awards. As the fair value of liability awards is required to be re-measured each period end, stock compensation expense amounts recognized in future periods for these awards will vary. The estimated future cash payments of these awards are presented as liabilities within Other current liabilities and Other long-term liabilities inthe consolidated balances sheets.
Restricted Stock Units
The Company granted 5.5 million restricted stock units during the third quarter of 2020 to certain officers (non-NEOs) and employees that are settleable in cash upon vesting. The restricted stock units vest annually in one-third increments over a three-year service period, with the first portion vesting on September 1, 2021. After one year from the grant date, however, the remaining two-thirds of unvested restricted stock units granted to non-NEOs can vest immediately, on an accelerated basis, if they meet certain market-based vesting criteria equal to the maximum return percentage discussed below for at least 20 out of any 30 consecutive trading days. Additionally, the restricted stock units include maximum and minimum return amounts equal to 400% and 25%, respectively, of the closing market price of the Company’s Common Stock on the grant date. As of March 31, 2021, there was $8.0 million of unrecognized compensation cost, which represents the unvested portion of the fair value of the restricted stock units and will be recognized over a weighted average period of 1.6 years or sooner if the accelerated vesting event occurs.
Performance Stock Units
The Company granted 5.5 million performance stock units (“PSU”) during third quarter of 2020 to certain executive officers that will be settled in cash and are subject to market-based vesting criteria as well as a three-year service condition. Vesting at the end of the three-year service period is subject to the condition that the Company’s stock price increases by a greater percentage, or
CENTENNIAL RESOURCE DEVELOPMENT, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
decreases by a lessor percentage, than the average percentage increase or decrease, respectively, of the stock price of a peer group of companies. The market-based conditions must be met in order for the PSU awards to vest, and it is therefore possible that no units could ultimately vest and cumulative stock compensation expense recognized for these awards would then be reduced to zero. As of March 31, 2021, there was $29.8 million of unrecognized compensation cost that represents the unvested portion of the fair value of the PSUs at March 31, 2021 and will be recognized over a weighted average period of 2.25 years.
Liability Awards Fair Value The fair value of the restricted stock units and performance stock units was estimated using a Monte Carlo valuation model as of the balance sheet date. The Monte Carlo valuation model is based on random projections of stock price paths and must be repeated numerous times to achieve a probabilistic assessment. Expected volatility was calculated based on the historical volatility of the Company’s Common Stock as well as the peer companies that are specified in the PSU award agreement. The risk-free rate is based on U.S. Treasury yield curve rates with maturities consistent with the remaining vesting or performance period.
The following table summarizes the key assumptions and related information used to determine the fair value of the liability awards as of March 31, 2021:
| | | | | | | | | | | |
| Restricted stock units | | Performance stock units |
| | | |
| Number of simulations | 10,000,000 | | 10,000,000 |
| Expected stock volatility | 133.5% | | 137.3% |
| Dividend yield | 0% | | 0% |
| Risk-free interest rate | 0.2% | | 0.2% |
Note 7—6—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 and Collar 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.price, or costless collars to establish fixed price floors and ceilings. All transactions are settled in cash with one party paying the other for the resulting difference in price multiplied by the contract volume.
CENTENNIAL RESOURCE DEVELOPMENT, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
The following table summarizes the approximate volumes and average contract prices of swapderivative contracts the Company had in place as of June 30, 2020:March 31, 2021:
|
| | | | | | | | | | | |
| | 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 |
|
| | | | | | | | | | | | | | | | | | | | | | | |
| Period | | Volume (Bbls) | | Volume
(Bbls/d) | | Wtd. Avg. Crude Price ($/Bbl)(1) |
| Crude oil swaps | | | | | | | |
| NYMEX WTI | April 2021 - June 2021 | | 1,183,000 | | | 13,000 | | | $43.18 |
| July 2021 - September 2021 | | 736,000 | | | 8,000 | | | 45.87 |
| October 2021 - December 2021 | | 644,000 | | | 7,000 | | | 45.59 |
| | | | | | | |
| | | | | | | |
| | | | | | | |
| ICE Brent | April 2021 - June 2021 | | 409,500 | | | 4,500 | | | $54.98 |
| July 2021 - September 2021 | | 184,000 | | | 2,000 | | | 48.25 |
| October 2021 - December 2021 | | 184,000 | | | 2,000 | | | 48.50 |
| | | | | | | |
| | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Period | | Volume (Bbls) | | Volume
(Bbls/d) | | Wtd. Avg. Collar Price Ranges ($/Bbl)(2) |
| Crude oil collars | April 2021 - June 2021 | | 227,500 | | | 2,500 | | | $ | 42.00 | | - | $ | 51.14 | |
| July 2021 - September 2021 | | 138,000 | | | 1,500 | | | 46.33 | | - | 55.40 | |
| October 2021 - December 2021 | | 92,000 | | | 1,000 | | | 42.00 | | - | 50.10 | |
| | | | | | | | | | | | | | | | | | | | | | | |
| Period | | Volume (Bbls) | | Volume
(Bbls/d) | | Wtd. Avg. Differential ($/Bbl)(3) |
| Crude oil basis differential swaps | April 2021 - June 2021 | | 1,183,000 | | | 13,000 | | | $0.11 |
| July 2021 - September 2021 | | 736,000 | | | 8,000 | | | 0.26 |
| October 2021 - December 2021 | | 644,000 | | | 7,000 | | | 0.26 |
| | | | | | | |
| | | | | | | |
(1) These crude oil swap transactions are settled based on either the NYMEX WTI or ICE Brent index price, as applicable, on each trading day within the specified monthly settlement period versus the contractual swap price for the volumes stipulated.
(2) These crude oil collars are settled based on the NYMEX WTI price on each trading day within the specified monthly settlement period versus the contractual floor and ceiling prices for the volumes stipulated.
(3) These oil basis swap transactions are settled based on the difference between the arithmetic average of ARGUS MIDLAND WTI and ARGUS WTI CUSHING indices, during each applicable monthly settlement period.
CENTENNIAL RESOURCE DEVELOPMENT, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
| | | | | | | | | | | | | | | | | | | | | | | |
| Period | | Volume (MMBtu) | | Volume (MMBtu/d) | | Wtd. Avg. Gas Price ($/MMBtu)(1) |
| Natural gas swaps | April 2021 - June 2021 | | 3,640,000 | | | 40,000 | | | $2.89 |
| July 2021 - September 2021 | | 3,680,000 | | | 40,000 | | | 2.89 |
| October 2021 - December 2021 | | 3,680,000 | | | 40,000 | | | 2.95 |
| January 2022 - March 2022 | | 1,800,000 | | | 20,000 | | | 3.00 |
| | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | |
| Period | | Volume (MMBtu) | | Volume (MMBtu/d) | | Wtd. Avg. Differential ($/MMBtu)(2) |
| Natural gas basis differential swaps | April 2021 - June 2021 |
| 3,640,000 | |
| 40,000 | | | $(0.30) |
| July 2021 - September 2021 | | 3,680,000 | | | 40,000 | | | (0.30) |
| October 2021 - December 2021 | | 3,680,000 | | | 40,000 | | | (0.28) |
| January 2022 - March 2022 | | 1,800,000 | | | 20,000 | | | (0.26) |
| |
(1)
| These crude oil swap transactions are settled based on the NYMEX WTI price on each trading day within the specified monthly settlement period. |
| |
(2)
| These oil basis swap transactions are settled based on the difference between the arithmetic average of ARGUS MIDLAND WTI and ARGUS WTI CUSHING indices, during each applicable settlement period. |
|
| | | | | | | | | | | |
| Period |
| Volume (MMBtu) |
| Volume (MMBtu/d) |
| Weighted Average Fixed Price ($/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)(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 versus the contractual swap price for the volumes stipulated. (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 monthly settlement period. | 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 Statementsconsolidated statements of Operations.operations. All derivative instruments are recorded at fair value in the Consolidated Balance Sheets,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 Statementsconsolidated statements of Operationsoperations 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 | ) |
| | | | | | | | | | | | | | | |
| Three Months Ended March 31, | | |
| (in thousands) | 2021 | | 2020 | | | | |
| | | | | | | |
| | | | | | | |
| Net gain (loss) on derivative instruments | $ | (51,199) | | | $ | (8,505) | | | | | |
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 Sheetsconsolidated 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 Sheetsconsolidated 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 |
|
| | | | | | | | | | | | | | | | | | | | | | | |
| Balance Sheet Classification | | Gross Fair Value Asset/Liability Amounts | | Gross Amounts Offset(1) | | Net Recognized Fair Value Assets/Liabilities |
| (in thousands) | | | March 31, 2021 |
| Derivative Assets | | | | | | | |
| Commodity contracts | Prepaid and other current assets | | $ | 2,071 | | | $ | (2,071) | | | $ | 0 | |
| | | | | | | |
| Derivative Liabilities | | | | | | | |
| Commodity contracts | Other current liabilities | | 48,593 | | | (2,071) | | | 46,522 | |
| | | | | | | |
| | | | | | | |
| | | December 31, 2020 |
| Derivative Assets | | | | | | | |
| Commodity contracts | Prepaid and other current assets | | $ | 6,131 | | | $ | (6,131) | | | $ | 0 | |
| Other noncurrent assets | | 152 | | $ | (100) | | | 52 |
| Derivative Liabilities | | | | | | | |
| Commodity contracts | Other current liabilities | | $ | 24,392 | | | $ | (6,131) | | | $ | 18,261 | |
| Other noncurrent liabilities | | $ | 100 | | | $ | (100) | | | $ | 0 | |
| |
(1) The Company has agreements in place with each 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. | 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.
CENTENNIAL RESOURCE DEVELOPMENT, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
Note 8—7—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 |
| | — |
|
| | | | | | | | | | | | | | | | | |
| (in thousands) | Level 1 | | Level 2 | | Level 3 |
| March 31, 2021 | | | | | |
| | | | | |
| Total liabilities | 0 | | | 46,522 | | | 0 | |
| December 31, 2020 | | | | | |
| Total assets | $ | 0 | | | $ | 52 | | | $ | 0 | |
| Total liabilities | 0 | | | 18,261 | | | 0 | |
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—6—Derivative Instruments for details of the gross and net derivatives assets, liabilities and offset amounts presented in the Consolidated Balance Sheets.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.
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
CENTENNIAL RESOURCE DEVELOPMENT, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
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—4—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 Notessenior 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.exchange. 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 |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | March 31, 2021 | | December 31, 2020 |
| | Carrying Value | | Principal Amount | | Fair Value | | Carrying Value | | Principal Amount | | Fair value |
Credit facility due 2023(1) | | $ | 160,000 | | | $ | 160,000 | | | $ | 160,000 | | | $ | 330,000 | | | $ | 330,000 | | | $ | 330,000 | |
8.00% Senior Secured Notes due 2025(2) | | 104,916 | | | 127,073 | | | 126,438 | | | 103,901 | | | 127,073 | | | 114,366 | |
5.375% Senior Notes due 2026(2) | | 285,063 | | | 289,448 | | | 254,714 | | | 284,867 | | | 289,448 | | | 206,955 | |
6.875% Senior Notes due 2027(2) | | 350,064 | | | 356,351 | | | 317,152 | | | 349,856 | | | 356,351 | | | 254,791 | |
3.25% Convertible Notes due 2028(2) | | 163,711 | | | 170,000 | | | 161,772 | | | 0 | | | 0 | | | 0 | |
| |
(1) (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. | 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. |
CENTENNIAL RESOURCE DEVELOPMENT, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
Note 9—8—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 equity-based restricted stock and performance stock units, outstanding stock options, withholding amounts from the employee stock purchase plan and warrants, all using the treasury stock method, and (ii) the Company’s Class C Common Stockcommon stock outstanding, prior to the Conversionconversion of remaining Class C shares in the second quarter of 2020, and potential shares issuable under our Convertible Senior Notes, both 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 |
|
| | | | | | | | | | | | | | | |
| Three Months Ended March 31, | | |
| (in thousands, except per share data) | 2021 | | 2020 | | | | |
| Net income (loss) attributable to Class A Common Stock | $ | (34,645) | | | $ | (547,983) | | | | | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
| Basic weighted average shares of Class A Common Stock outstanding | 278,935 | | | 275,952 | | | | | |
| | | | | | | |
| | | | | | | |
| Diluted weighted average shares of Class A Common Stock outstanding | 278,935 | | | 275,952 | | | | | |
| | | | | | | |
| Basic net earnings (loss) per share of Class A Common Stock | $ | (0.12) | | | $ | (1.99) | | | | | |
| Diluted net earnings (loss) per share of Class A Common Stock | $ | (0.12) | | | $ | (1.99) | | | | | |
The Company recognized a net loss during the sixthree months ended June 30,March 31, 2021 and 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 March 31, | | |
| (in thousands) | 2021 | | 2020 | | | | |
| Out-of-the-money stock options | 2,294 | | | 4,782 | | | | | |
| Restricted stock | 9,565 | | | 5,143 | | | | | |
| Employee Stock Purchase Plan | 41 | | | 1,138 | | | | | |
| Weighted average shares of Class C Common Stock | 0 | | | 1,034 | | | | | |
| Warrants | 8,000 | | | 8,000 | | | | | |
| Performance stock units | 399 | | | 0 | | | | | |
| Convertible Senior Notes | 27,074 | | | 0 | | | | | |
|
| | | | | | | | | | | |
| | 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 |
|
CENTENNIAL RESOURCE DEVELOPMENT, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
Note 10—9—Transactions with Related Parties
Riverstone Investment Group LLC 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 presentedincluded in the Consolidated Statementsconsolidated statements of Operationsoperations for the periods indicated, as well as the related net receivables outstanding as of the balance sheet dates:
| | | | | | | | | | | | | | | |
| Three Months Ended March 31, | | |
| (in thousands) | 2021 | | 2020 | | | | |
| Oil and gas sales | $ | 1,075 | | | $ | 1,088 | | | | | |
| Gathering, processing and transportation expenses | 1,205 | | | 953 | | | | | |
|
| | | | | | | | | | | | | | | |
| 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 |
|
| | | | | | | | | | | |
| (in thousands) | March 31, 2021 | | December 31, 2020 |
Accounts receivable, net(1) | $ | 1,796 | | | $ | 994 | |
(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 forheld $106.3 million of the Company’s Senior Secured Notes. Riverstone’s participation inNotes as of March 31, 2021 and December 31, 2020. No interest payments associated with the Debt Exchange represented $106.3 million (or 74%) ofSenior Secured Notes were made to Riverstone during the total extinguishment gain recognized in the consolidated statements of operations.three months ended March 31, 2021 or 2020.
Note 11—10—Commitments and Contingencies
Commitments
The Company routinely enters into, extends or amends operating agreements in the ordinary course of business. During the sixthree 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,March 31, 2021, and affirmed May 31, 2025 as the end of the initial term of the agreement. There hasthere have been no other material, non-routine changes in commitments during the sixthree months ended June 30, 2020.March 31, 2021. Please refer to Note 13—Commitments and Contingencies included in Part II, Item 8 in the Company’s 20192020 Annual Report.
The Company has a firm crude oil sales agreement with a large integrated oil company, and in the first quarter of 2021, new pricing terms under this agreement went into effect. Utilizing this integrated oil company’s transport capacity out of the Permian Basin, the agreement provides for firm gross sales of 30,000 Bbls/d over the next 4 years and is based upon prevailing market prices of ICE Brent less contractual differentials. These pricing terms are resulting in realized prices that currently have wider differentials than those being realized under the Company’s other oil marketing agreements. However, if the oil price differential between the ICE Brent and NYMEX WTI indices widen in the future, the oil price realized under this delivery commitment will improve relative to the prices realized under the Company’s other oil sales contracts. Under-delivery of volumes that are committed under this agreement would result in a financial obligation to the Company, although the Company’s current production level (on a gross basis) is, and the Company believes its future production will be, sufficient to fulfill this physical delivery commitment.
Contingencies
The Company may at times be subject to various commercial or regulatory claims, prior period adjustments from service providers, 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, other than those discussed below, 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
CENTENNIAL RESOURCE DEVELOPMENT, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
In February 2021, the Permian Basin was impacted by record-low temperatures and a severe winter storm (“Winter Storm Uri”) that resulted in multi-day electrical outages and shortages, pipeline and infrastructure freezes, transportation disruptions, and regulatory actions in Texas, which led to significant increases in gas prices, gathering, processing and transportation fees and electrical rates during this time. As a result, many oil and gas operations, including upstream producers like the Company, as well as gas processors and purchasers, and transportation providers experienced operational disruptions. During this time, the Company was unable to utilize the entire volume of its reserved capacity on pipelines and as a result has made certain force majeure declarations. One third-party transportation provider has filed a lawsuit against the Company claiming compensation for the full amount of the reserved capacity, both utilized and unutilized. The Company has made a payment for the utilized capacity, and filed a separate lawsuit against the transportation provider requesting declaratory relief for the purpose of construing the provisions of the transportation agreement relating to the unutilized capacity. At this time, the Company believes that a loss is reasonably possible in relation to these matters and such amount could range from 0 to $7.6 million, and no amount in that range is a better estimate than any other.
Other than the matter above, 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—11—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.
CENTENNIAL RESOURCE DEVELOPMENT, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
Oil and gas revenues presented within the Consolidated Statementsconsolidated statements of Operationsoperations 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 |
|
| | | | | | | | | | | | | | | |
| Three Months Ended March 31, | | |
| 2021 | | 2020 | | | | |
| Operating revenues (in thousands): | | | | | | | |
| Oil sales | $ | 133,726 | | | $ | 170,505 | | | | | |
| Natural gas sales | 35,451 | | | 8,358 | | | | | |
| NGL sales | 23,214 | | | 13,906 | | | | | |
| Oil and gas sales | $ | 192,391 | | | $ | 192,769 | | | | | |
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 gathering and processing entity at the inlet of the gas plant processinggathering 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 Statementsconsolidated statements of Operations.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.
CENTENNIAL RESOURCE DEVELOPMENT, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
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.consolidated balance sheets. As of June 30, 2020March 31, 2021 and December 31, 2019,2020, such receivable balances were $41.5$54.0 million and $76.6$41.7 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 sixthree months ended June 30,March 31, 2021 and 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—12—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.
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,March 31, 2021, these leases have remaining lease terms ranging from two monthsone month to two years,1 year, 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.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, 2020March 31, 2021 |
| Weighted-average discount rate | | 4.765.13 | % |
Weighted-average remaining lease term (years)(months) | | 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.
CENTENNIAL RESOURCE DEVELOPMENT, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
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.term as either expenses to the consolidated statements of operations or capitalized to the consolidated balance sheets. 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, | | Three Months Ended March 31, | |
| (in thousands) | 2020 | | 2019 | | 2020 | | 2019 | (in thousands) | 2021 | | 2020 | |
Lease costs(1) | | | | | | | | |
| Lease costs | | Lease costs | | | | |
| Operating lease cost | $ | 1,595 |
| | $ | 10,806 |
| | $ | 6,271 |
| | $ | 21,393 |
| Operating lease cost | $ | 873 | | | $ | 4,305 | | |
| Variable lease cost | 3,669 |
| | 703 |
| | 5,021 |
| | 1,504 |
| Variable lease cost | 9 | | | 1,207 | | |
Short-term lease cost(2) | 12,217 |
| | 16,684 |
| | 31,827 |
| | 28,908 |
| |
| Short-term lease cost | | Short-term lease cost | 7,194 | | | 17,825 | | |
| Total lease cost | $ | 17,481 |
| | $ | 28,193 |
| | $ | 43,119 |
| | $ | 51,805 |
| Total lease cost | $ | 8,076 | | | $ | 23,337 | | |
| |
(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.
|
Table of Contents | | | | | | | | | | | | | | | |
| Three Months Ended March 31, | | |
| (in thousands) | 2021 | | 2020 | | | | |
| Operating lease liability payments: | | | | | | | |
| Cash used in operating activities | $ | 873 | | | $ | 2,503 | | | | | |
| Cash used in investing activities | $ | 0 | | | $ | 1,802 | | | | | |
| | | | | | | |
| Right-of-use assets recognized (derecognized) with offsetting operating lease liabilities | $ | (32) | | | $ | (829) | | | | | |
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, 2020March 31, 2021 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 |
|
| | | | | |
| (in thousands) | Total(2) |
2021(1) | $ | 2,338 | |
| 2022 | 425 | |
| |
| Total lease payments | 2,763 | |
| Less: imputed interest | (66) | |
Present value of lease liabilities (3) | $ | 2,697 | |
| |
(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.
|
(1) Excludes payments made during the three months ended March 31, 2021.
(2) Total lease payments exclude variable lease payments which can be charged under the terms of the lease agreements.
(3) This amount is included in current liabilities in the line item Operating lease liabilities in the consolidated balance sheets as of March 31, 2021.
Note 14—13—Subsequent Events
Senior Secured Notes Redemption
In July 2020,April 2021, the Company redeemed at par all of its one outstanding share of Series A Preferred Stock, par value $0.0001 per share (the “Series A Preferred Stock”),$127.1 million held by aggregate principal amount of Senior Secured Notes,NGP X US Holdings, L.P. (“NGP”), a former indirect equity owner which was the intended use of CRP. The Series A Preferred Stock became redeemable byproceeds from the Convertible Senior Notes offering. Additionally, the Company paid accrued interest on the Senior Secured Notes of $3.8 million in connection with the redemption. The Company plans to record a loss on debt extinguishment of approximately $22.2 million related to the write-off of all unamortized debt issuance costs and discount amounts associated with the Senior Secured Notes being redeemed. Further, the availability blocker of $31.8 million, which had been reducing the amount available to be borrowed under the Credit Agreement, was removed as NGP ceased to own at least 5,000,000 sharesa result of Class A Common Stock.this note redemption.
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, future 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 20192020 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 primarilyconcentrated 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 recent2020 worldwide outbreak of COVID-19, the uncertainty regarding theits impact of COVID-19 and various governmental actions taken to mitigate the impacteffects of COVID-19 have resulted in an unprecedented decline in the demand for oil and natural gas. At the same time,gas throughout 2020. In addition, the decision by Saudi Arabia in March 2020 to drastically reduce export prices and increase oil production in March 2020 (the “Saudi-Russia oil price war”) followed by curtailment agreements among OPECOrganization of Petroleum Exporting Countries (“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 declineHowever, in commodity prices starting inApril of 2020, the first quartermembers 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,throughout the year, while U.S. producers substantially reduced or suspended drilling activity, and in most cases curtailed production,completion activity due to low oil prices and poor economics. These actions
The demand for oil and natural gas continued to remain low in early 2021 due to continued uncertainty regarding the impacts of COVID-19. OPEC and other producing countries extended their production cuts through the first quarter of 2021 with gradual output increases expected to begin in the second quarter of 2021. Further, U.S. drilling activity only began to increase in the fourth quarter of 2020 and has continued to increase steadily since. The continued reduction in overall oil supply paired with the expectation of a recovery in global oil demand due to the availability of COVID-19 vaccinations and less governmental mandated restrictions have aided in a partialthe recovery of global commodity prices.prices during the first quarter of 2021. Specifically, WTI spot prices for crude oil fell toreached a high of $66.09 per barrel on March 5, 2021 from a low of negative ($37.63)$37.63 per barrel on April 20, 2020 (due(which was 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 fluctuations in global supply and demand, inventory levels, the continued effects from COVID-19, geopolitical events, weather conditions, the global transition to alternative energy sources and other factors. The following table highlights the quarterly average NYMEX price trends for crude oil and natural gas since the first quarter of 2018:2019:
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | 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. | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| 2019 | | 2020 | | 2021 |
| Q1 | | Q2 | | Q3 | | Q4 | | Q1 | | Q2 | | Q3 | | Q4 | | Q1 | | | | |
| Crude oil (per Bbl) | $ | 54.90 | | | $ | 59.81 | | | $ | 56.45 | | | $ | 56.94 | | | $ | 46.19 | | | $ | 28.00 | | | $ | 40.93 | | | $ | 42.66 | | | $ | 57.84 | | | | | |
| Natural gas (per MMBtu) | $ | 2.88 | | | $ | 2.51 | | | $ | 2.33 | | | $ | 2.34 | | | $ | 1.88 | | | $ | 1.65 | | | $ | 1.95 | | | $ | 2.47 | | | $ | 3.44 | | | | | |
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 “Resultsincurred in the first quarter of Operations”)2020) 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,
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,vendors, 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 workedhave been working remotely during the months of March and April but have started to report backor reporting to our offices on a limited basis starting in mid-May.basis. We have taken various precautionary measures with respect to our operational employees, direct contractors and employees who returnreturned to our offices or job sites 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 or contractors who have shown signs or symptoms of COVID-19 (regardless of whether such employeeperson 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 (the “CDC”) as well as local and state authorities, (iv) requiring all employees and contractors to have a fit-test for and wear KN-95 type respirators while in our offices and work sites, and (v) encouraging all employees and contractors to follow the CDC recommended preventive measures (including those mentioned above) to limit the spread of COVID-19. We have not experienced any operational disruptions (including disruptions from our suppliers and service providers) as a result of the COVID-19 outbreak.
20202021 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-rigtwo-rig drilling program during the majority of the first quarter of 2020,2021, which enabled us to complete and bring online 2611 gross operated wells with an average effective lateral length of approximately 7,200 feet8,100 feet.
In February 2021, the Permian Basin was impacted by record-low temperatures and a severe winter storm (“Winter Storm Uri”) that caused multi-day electrical outages and shortages, pipeline and infrastructure freezes, and transportation disruptions, which further lead to significant increases in gas prices, gathering, processing and transportation fees and electrical rates during this time. Our operations were impacted by Winter Storm Uri and lead to a partial shut-in of certain wells and associated production for about seven days during the first half of 2020.
Dueevent. Refer 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 operationdiscussion below for the remainder ofcurrent impacts from 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 madeWinter Storm Uri 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.for the three months ended March 31, 2021.
Financing Highlights
On May 22, 2020,March 19, 2021, we completedissued $150.0 million of 3.25% senior convertible notes due 2028 (the “Convertible Senior Notes”) in a public offering. On March 26, 2021, the Company issued an opportunistic private exchangeadditional $20.0 million of Convertible Senior Notes pursuant to the exercise of the underwriters’ over-allotment option to purchase additional Convertible Senior Notes. The issuance resulted in net proceeds of $163.7 million, after deducting debt issuance costs of $6.3 million, and such proceeds were used to fund the cost of entering into capped call spread transactions of $14.7 million and repay borrowing outstanding under CRP’s revolving credit facility. In April 2021, we redeemed at par all 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 lien2025 senior secured notes due 2025 (the “Senior Secured Notes”). This transaction resulted in($127.1 million), which was the removalintended use of $127.1 million in principal amount of Senior Unsecured Notesproceeds from the long-term debt balance in our Consolidated Balance Sheets.Convertible Senior Notes offering.
On May 1, 2020, we entered into amendments toIn connection with CRP’s amended and restated credit agreement (the “2020 Amendments”) with the lenders to our existing credit agreement. Pursuant to the 2020 Amendments,facility spring 2021 semi-annual borrowing base redetermination, the borrowing base and levelamount of elected commitments were reduced toreaffirmed at $700.0 million. The 2020 Amendments that the lenders approved permitted the issuance
Results of Operations
Three Months Ended June 30, 2020March 31, 2021 Compared to Three Months Ended June 30, 2019March 31, 2020
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 | )% |
| | | | | | | | | | | | | | | | | | | | | | | |
| Three Months Ended March 31, | | Increase/(Decrease) |
| 2021 | | 2020 | | $ | | % |
| Net revenues (in thousands): | | | | | | | |
| Oil sales | $ | 133,726 | | | $ | 170,505 | | | $ | (36,779) | | | (22) | % |
| Natural gas sales | 35,451 | | | 8,358 | | | 27,093 | | | 324 | % |
| NGL sales | 23,214 | | | 13,906 | | | 9,308 | | | 67 | % |
| Oil and gas sales | $ | 192,391 | | | $ | 192,769 | | | $ | (378) | | | — | % |
| | | | | | | |
| Average sales prices: | | | | | | | |
| Oil (per Bbl) | $ | 52.62 | | | $ | 45.14 | | | $ | 7.48 | | | 17 | % |
| Effect of derivative settlements on average price (per Bbl) | (9.43) | | | (0.01) | | | (9.42) | | | (94,200) | % |
| Oil net of hedging (per Bbl) | $ | 43.19 | | | $ | 45.13 | | | $ | (1.94) | | | (4) | % |
| | | | | | | |
| Average NYMEX price for oil (per Bbl) | $ | 57.84 | | | $ | 46.19 | | | $ | 11.65 | | | 25 | % |
| Oil differential from NYMEX | (5.22) | | | (1.05) | | | (4.17) | | | (397) | % |
| | | | | | | |
| Natural gas (per Mcf) | $ | 3.79 | | | $ | 0.78 | | | $ | 3.01 | | | 386 | % |
| Effect of derivative settlements on average price (per Mcf) | 0.12 | | | — | | | 0.12 | | | 100 | % |
| Natural gas net of hedging (per Mcf) | $ | 3.91 | | | $ | 0.78 | | | $ | 3.13 | | | 401 | % |
| | | | | | | |
| Average NYMEX price for natural gas (per Mcf) | $ | 3.44 | | | $ | 1.88 | | | $ | 1.56 | | | 83 | % |
| Natural gas differential from NYMEX | 0.35 | | | (1.10) | | | 1.45 | | | 132 | % |
| | | | | | | |
| NGL (per Bbl) | $ | 29.78 | | | $ | 14.30 | | | $ | 15.48 | | | 108 | % |
| | | | | | | |
| Net production: | | | | | | | |
| Oil (MBbls) | 2,542 | | | 3,778 | | | (1,236) | | | (33) | % |
| Natural gas (MMcf) | 9,343 | | | 10,715 | | | (1,372) | | | (13) | % |
| NGL (MBbls) | 780 | | | 972 | | | (192) | | | (20) | % |
Total (MBoe)(1) | 4,878 | | | 6,536 | | | (1,658) | | | (25) | % |
| | | | | | | |
| Average daily net production: | | | | | | | |
| Oil (Bbls/d) | 28,239 | | | 41,512 | | | (13,273) | | | (32) | % |
| Natural gas (Mcf/d) | 103,806 | | | 117,751 | | | (13,945) | | | (12) | % |
| NGL (Bbls/d) | 8,662 | | | 10,683 | | | (2,021) | | | (19) | % |
Total (Boe/d)(1) | 54,202 | | | 71,820 | | | (17,618) | | | (25) | % |
| |
(1) Calculated by converting natural gas to oil equivalent barrels at a ratio of six Mcf of natural gas to one Boe.
| 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, 2020March 31, 2021 were $153.7$0.4 million (or 63%0.2%) lower than total net revenues for the three months ended June 30, 2019.March 31, 2020. Revenues are a function of oil, natural gas and NGL volumes sold and average commodity prices realized.
Average realized sales prices for oil, residue gas and NGLs decreasedincreased in the secondfirst quarter of 20202021 compared to the same 2019 period.2020 period by 17%, 386% and 108% respectively. The average price for oil before the effects of hedging decreased 61% and the average price for NGLs decreased 52% between periods. The 61% decrease17% increase in the average realized oil price before the effects of hedging was the result of lowerhigher NYMEX crude prices between periods (average NYMEX prices decreased 53%increased 25%) and, which was partially offset by wider oil differentials (an($4.17 per Bbl wider) associated with our firm oil sales agreement that is based upon the prevailing market price of ICE Brent less contractual differentials. The 386% increase in average realized sales price of $1.35natural gas before the effects of hedging was due to higher NYMEX prices (average prices increased 83%) and improved gas differentials ($1.45 per Bbl)Mcf). The 52% decreaseincrease in average realized NGL prices of 108% between periods was primarily attributable to lowerhigher Mont Belvieu spot prices for plant products in the secondfirst quarter of 20202021 as compared to the secondfirst 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 2019.2020. The market prices for oil, natural gas and NGLs were significantlyhave all been impacted by lowerhigher global demand globally for oil and gas compared to the first quarter of 2020 when prices decreased significantly as a result of COVID-19 as well as commodityand supply disruptions both of which combined resulted in significantfrom the Saudi-Russia oil price declines startingwar, beginning in March 2020 as discussed in the market conditions section above. Additionally, the first quarter 2021 realized price for natural gas in the Permian Basin was impacted by Winter Storm Uri, which caused gas pipeline and supply disruptions and resulted in significant natural gas price increases in the area during this period.
Net production volumes for oil, natural gas, and NGLs decreased 33%, 13% and 17%20%, respectively, while natural gas increased 2% between periods.respectively. The crude oil production volume decrease was primarily the result of (i) the temporary suspension of ourless drilling and completion activity inover the second quarterpast 12 months as a result of 2020,depressed oil and gas prices, 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 wellsbeing placed on production in the Delaware Basin since the secondfirst quarter of 2019, which2020. This added 1,604422 MBbls of net oil production to the three months ended June 30,March 31, 2021 as compared to 86 wells brought online since the first quarter of 2019 that added 1,864 MBbls of net oil production to the first quarter of 2020. Oil volume declines in the first quarter of 2021 were additionally impacted by the temporary shut-in of our wells during mid-February as a result of Winter Storm Uri and normal field production declines across our existing wells. 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 secondfirst quarter of 2020,2021, the main processoramount of our raw gas operated in partial ethane-rejection for two-thirdsflared as a percentage of the quarter,wellhead gas produced was significantly less 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 thesame 2020 period, resulting in an increase (2%) ina higher ratio of natural gas volumes and a decrease (17%) in NGL volumes between periods.produced compared to oil volumes during the period.
Operating Expenses. The following table sets forth selected operating expense data for the periods indicated:
| | | | Three Months Ended June 30, | | Increase/(Decrease) | | Three Months Ended March 31, | | Increase/(Decrease) |
| | 2020 | | 2019 | | $ |
| % | | 2021 | | 2020 | | $ | | % |
| Operating costs (in thousands): | | | | |
|
|
| Operating costs (in thousands): | | | | | | | |
| Lease operating expenses | $ | 25,839 |
| | $ | 34,885 |
| | $ | (9,046 | ) |
| (26 | )% | Lease operating expenses | $ | 25,861 | | | $ | 32,639 | | | $ | (6,778) | | | (21) | % |
| Severance and ad valorem taxes | 5,696 |
| | 17,186 |
| | (11,490 | ) |
| (67 | )% | Severance and ad valorem taxes | 12,583 | | | 16,573 | | | (3,990) | | | (24) | % |
| Gathering, processing and transportation expenses | 17,284 |
| | 16,243 |
| | 1,041 |
|
| 6 | % | Gathering, processing and transportation expenses | 20,625 | | | 16,939 | | | 3,686 | | | 22 | % |
| Operating costs per Boe: | | | | |
|
|
|
| Operating costs per Boe: | |
| Lease operating expenses | $ | 4.16 |
| | $ | 5.04 |
| | $ | (0.88 | ) |
| (17 | )% | Lease operating expenses | $ | 5.30 | | | $ | 4.99 | | | $ | 0.31 | | | 6 | % |
| Severance and ad valorem taxes | 0.92 |
| | 2.48 |
| | (1.56 | ) |
| (63 | )% | Severance and ad valorem taxes | 2.58 | | | 2.54 | | | 0.04 | | | 2 | % |
| Gathering, processing and transportation expenses | 2.78 |
| | 2.34 |
| | 0.44 |
|
| 19 | % | Gathering, processing and transportation expenses | 4.23 | | | 2.59 | | | 1.64 | | | 63 | % |
Lease Operating Expenses. Lease operating expenses (“LOE”) for the three months ended June 30, 2020March 31, 2021 decreased $9.0$6.8 million compared to the three months ended June 30, 2019.March 31, 2020. Lower LOE for the secondfirst quarter of 20202021 was primarily related to (i) a $7.6$4.6 million decrease in workover expense between periods as a result of lower workover activity and a $1.4 million decrease in variable and semi-variablebetween periods; (ii) lower well 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 asexpenses associated with cost reduction initiatives we have undertaken such as lowering contract labor costs and decreasing monthly equipment rentals, which were achieved byincluding moving multiple wells off generators to more efficientcost-efficient electrical line-power.line-power and switching wells away from electric submersible pumps to more reliable and lower cost gas lift; and (iii) lower variable and semi-variable costs stemming from the 25% production decline between periods. These decreases were partially offset by LOE costs associated with our higher well count, which increased to 397 gross operated horizontal wells as of March 31, 2021 from 377 gross operated horizontal wells as of March 31, 2020 as a result of our drilling activity adding 20 wells since the first quarter of 2020.
LOE per Boe was $5.30 for the first quarter of 2021, which represents an increase of $0.31 per Boe (or 6%) from the first quarter of 2020. This increase was primarily driven by per BOE cost increases between periods 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)other equipment, wellhead chemical costs and water handling costs. These increases were partially offset by the lower level of workover activity as well as cost reduction initiatives we have undertaken, both of which are discussed above.
Severance and Ad Valorem Taxes. Severance and ad valorem taxes for the three months ended June 30, 2020March 31, 2021 decreased $11.5$4.0 million compared to the three months ended June 30, 2019.March 31, 2020. 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 proved developed oil and natural gas reservesproperties and vary across the different counties in which we operate. Severance and adAd valorem taxes as a percentagedecreased $3.3 million between periods due to lower tax assessments on our oil and gas reserve values. Severance taxes remained consistent between periods at 5.3% of total net revenues decreased to 6.3% forduring the secondfirst quarter of 20202021 as comparedcomparable to 7.0% for5.5% during 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.prior year quarter.
Gathering, Processing and Transportation Expenses. Gathering, processing and transportation expenses (“GP&T”) for the three months ended June 30, 2020March 31, 2021 increased $1.0$3.7 million as compared to the three months ended June 30, 2019March 31, 2020. On a per Boe basis, GP&T likewise increased from $2.59 for the first quarter of 2020 to $4.23 for the first quarter of 2021. These increases were mainly attributable to (i) higher gas plant processing costs, which are primarily due tobased on natural gas and NGL prices both of which increased substantially between periods as discussed above, and (ii) a $2.4$0.9 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 March 31, |
| (in thousands, except per Boe data) | 2021 |
| 2020 |
| Depreciation, depletion and amortization | $ | 63,783 | | | $ | 101,258 | |
| Depreciation, depletion and amortization per Boe | $ | 13.08 | | | $ | 15.49 | |
|
| | | | | | | |
| 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$13.08 for the secondfirst quarter of 20202021 compared to $16.18$15.49 for the same period in 2019. The2020. This 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, wasmillion, combined with lower finding and development costs incurred on our recently completed wells. These downward impacts were partially offset by net downward revisions in our proved reserves duringsince the secondfirst quarter of 2020, which are 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.pricing.
Impairment and Abandonment Expense. During the three months ended June 30, 2020, $19.4 million ofMarch 31, 2021 impairment and abandonment expense was incurred$9.2 million and related to the amortization of leasehold expiration costs associated with individually insignificant unproved properties. During the three months ended March 31, 2020, impairment and abandonment expense was $611.3 million and consisted of (i) a $591.8 million non-cash impairment of our proved oil and gas properties as a result of depressed NYMEX oil and gas forward curves as of March 31, 2020, and (ii) $19.5 million 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.and Other Expenses. The following table summarizes our exploration expenseand other expenses for the periods indicated:
| | | | | | | | | | | |
| Three Months Ended March 31, |
| (in thousands) | 2021 |
| 2020 |
| Geological and geophysical costs | $ | 613 | | | $ | 1,993 | |
| Rig termination fees | — | | | 1,499 | |
| | | |
| Stock-based compensation - equity awards | 208 | | | 517 | |
| Stock-based compensation - liability awards | 167 | | | — | |
| Other expenses | 107 | | | — | |
| Exploration and other expenses | $ | 1,095 | | | $ | 4,009 | |
|
| | | | | | | |
| 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 |
|
Exploration expense was $4.1and other expenses were $1.1 million for the three months ended June 30, 2020March 31, 2021 compared to $3.9$4.0 million for the three months ended June 30, 2019.March 31, 2020. Exploration expenseand other expenses mainly consistsconsist 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 increasedecrease was primarily related to thea (i) $1.5 million decrease in rig termination fees, that were incurred when we reduced our drilling program from five rigs to one in the second quarterMarch of 2020, as a result of reducing our operated drilling activity in April of 2020 and(ii) $0.7 million in nonrecurring severance payments tolower ongoing G&G personnel resulting from ourcosts associated
with the 2020 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, and (iii) a $0.6 million decrease in higher costs incurred on G&G projectsproject costs 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.between periods.
General and Administrative Expenses. The following table summarizes our general and administrative (“G&A”) expenses for the periods indicated:
| | | | | | | | | | | |
| Three Months Ended March 31, |
| (in thousands) | 2021 | | 2020 |
| Cash general and administrative expenses | $ | 10,632 | | | $ | 12,978 | |
| Stock-based compensation - equity awards | 4,377 | | | 5,892 | |
| Stock-based compensation - liability awards | 10,247 | | | — | |
| Severance payments | — | | | — | |
| General and administrative expenses | $ | 25,256 | | | $ | 18,870 | |
|
| | | | | | | |
| | 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, 2020March 31, 2021 were $18.0$25.3 million compared to $18.4$18.9 million for the three months ended June 30, 2019.March 31, 2020. The lowerhigher G&A expenses incurred in the secondfirst quarter of 2021 was primarily the result of $10.2 million in stock compensation expense related to liability awards granted to G&A employees in the third quarter of 2020 that are settleable in cash upon vesting. These liability stock-based awards are recorded at their respective fair values, and such fair values are re-measured each balance sheet date (refer to Note 5—Stock-Based Compensation for additional information regarding the liability awards). This increase was partially offset by a decrease in cash G&A primarily related to $1.8 million in lower payroll and other personnel related costs and a $1.5 million decrease in equity-based stock compensation expense between periods, both of which were 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, | | Three Months Ended March 31, |
| (in thousands) | 2020 | | 2019 | (in thousands) | 2021 | | 2020 |
| Credit facility | $ | 3,159 |
| | $ | 879 |
| Credit facility | $ | 3,315 | | | $ | 2,167 | |
| 8.00% Senior Secured Notes due 2025 | 1,129 |
| | — |
| 8.00% Senior Secured Notes due 2025 | 2,541 | | | — | |
| 5.375% Senior Unsecured Notes due 2026 | 4,732 |
| | 5,375 |
| |
| 6.875% Senior Unsecured Notes due 2027 | 7,524 |
| | 8,594 |
| |
| 5.375% Senior Notes due 2026 | | 5.375% Senior Notes due 2026 | 3,889 | | | 5,374 | |
| 6.875% Senior Notes due 2027 | | 6.875% Senior Notes due 2027 | 6,125 | | | 8,594 | |
| 3.25% Convertible Senior Notes due 2028 | | 3.25% Convertible Senior Notes due 2028 | 172 | | | — | |
| Amortization of debt issuance costs and discount | 1,535 |
| | 775 |
| Amortization of debt issuance costs and discount | 1,847 | | | 799 | |
| Interest capitalized | (708 | ) | | (1,186 | ) | Interest capitalized | (404) | | | (513) | |
| Total | $ | 17,371 |
| | $ | 14,437 |
| Total | $ | 17,485 | | | $ | 16,421 | |
Interest expense was $2.9$1.1 million higher for the three months ended June 30, 2020March 31, 2021 as compared to the three months ended June 30, 2019March 31, 2020 primarily due to $2.3(i) $2.5 million in interest incurred on our Senior Secured Notes issued in May of 2020 in connection with our debt exchange; (ii) $1.1 million in increased interest expense incurred on our credit facility due to increased borrowings outstanding under the facilityborrowings; and $0.8(iii) $1.0 million in higher amortization related toof debt issuance costs and discount between periods. These increases were partially offset by lower interest expense incurred on our Senior Unsecured Notes during the first quarter of 2021, as $110.6 million of the 2026 Senior Notes and $143.7 million of the 2027 Senior Notes were extinguished in our debt discount recognized in connection with theexchange transaction. Refer to Note 3—Long-Term Debt Exchange.under Part I, Item I of this Quarterly Report for additional information on our Senior Notes and debt exchange transaction.
Our weighted average borrowings outstanding under our credit facility were $344.7$330.9 million versus $13.2$233.9 million for the three months ended June 30,March 31, 2021 and 2020, and 2019, respectively. Our credit facility’s weighted average effective interest rate (which is a LIBOR-based rate) was 3.1%3.5% and 4.0%2.8% for the three months ended June 30,March 31, 2021 and 2020, and 2019, respectively, as a result of lowerhigher LIBOR in the secondfirst quarter of 20202021 versus the prior year quarter.
Gain on exchangeTable of debt. ContentsA 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 intooutstanding 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, | | Three Months Ended March 31, |
| (in thousands) | 2020 | | 2019 | (in thousands) | 2021 | | 2020 |
| Settlement gains (losses) | $ | (6,894 | ) | | $ | 6,388 |
| |
| Realized cash settlement gains (losses) | | Realized cash settlement gains (losses) | $ | (22,886) | | | $ | (53) | |
| Non-cash mark-to-market derivative gain (loss) | (22,963 | ) | | (4,260 | ) | Non-cash mark-to-market derivative gain (loss) | (28,313) | | | (8,452) | |
| Total | $ | (29,857 | ) | | $ | 2,128 |
| Total | $ | (51,199) | | | $ | (8,505) | |
Income Tax Expense(Expense) Benefit. We recognizedThe following table summarizes our pre-tax income tax benefit of $1.9 million(loss) and income tax expense of $5.9 million(expense) benefit 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 periods indicated: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.
| | | | | | | | | | | |
| Three Months Ended March 31, |
| (in thousands) | 2021 | | 2020 |
| Income (loss) before income taxes | $ | (34,645) | | | $ | (633,553) | |
| Income tax (expense) benefit | — | | | 83,208 | |
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.
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.
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.
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 gas2021 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.
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.
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 differeddiffers 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;taxes, (ii) estimated permanent differences;differences, and (iii) any changes during the period in our deferred tax asset valuation allowance, such asallowance.
For the recognitionthree months ended March 31, 2021 and 2020, we recognized deferred tax asset valuation allowances of a $49.7$12.4 million valuation allowance in the first half of 2020and $55.6 million, respectively, against net operating loss carryforwards thatlosses (“NOLs”) we generated during those respective quarters, and such NOLs are not expectedestimated as unlikely to be realized.realized in future periods. These increases in the valuation allowance were the primary factor reducing our income tax benefits (based on the U.S. statutory rate) in each respective quarter to zero for the first quarter of 2021 and to $83.2 million for the first quarter of 2020.
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 oilprices, which have been and natural gas beganwill likely continue to decline significantly in March 2020 and continued to deteriorate and have remained volatile since. These lowerbe volatile. Lower commodity prices can negatively impact our cash flows and availabilityour ability 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 sixthree months ended June 30, 2020:March 31, 2021:
|
| | | |
| (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 |
|
| | | | | |
| (in millions) | Three Months Ended March 31, 2021 |
| Drilling, completion and facilities | $ | 70.6 | |
| Infrastructure, land and other | 2.3 | |
| |
| Total capital expenditures incurred | $ | 72.9 | |
We continually evaluate our capital needs and compare them to our capital resources. AsWe operated a result of the decline in crude oil prices and ongoing uncertainty regarding the oil supply-demand macro environment, we temporarily suspended alltwo-rig drilling and completion activities at the end ofprogram during the first quarterthree months of 2020 in order2021 and plan to preserve capital. Specifically, we reduced our operated drilling rig program to zerocontinue with two 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 now2021 to be between $240.0$260 million to $270.0$310 million, of which represents an approximate 60% reduction$250 million to $290 million is allocated to drilling, completion and facilities activity. We funded our capital expenditures for the three months ended March 31, 2021 entirely from cash flows from operations, and we expect to fund the mid-pointremainder of our original estimated2021 capex budget for 2020entirely from cash flows from operations as well, given current commodity price levels. We were free cash flow positive during the first quarter of $590 million2021 such that we were able to $690 million.partially pay down borrowings under our credit agreement during the period, and based upon current commodity prices, we expect to continue to pay down borrowings through expected free cash flow generation during the remainder of 2021.
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 completedissued 3.25% Convertible Senior Notes in March 2021, which resulted in net proceeds of $163.7 million. The proceeds were used to fund the Debt Exchange with respectcost of entering into capped call spread transactions of $14.7 million and to repay borrowings outstanding under CRP’s revolving credit facility during the first quarter of 2021. Subsequently in April 2021, we fully redeemed and repaid at par our Senior UnsecuredSecured Notes (defined below), which were due in May 20202025 and bore interest at 8.00% per year, which reducedwas the total principal amounts dueintended use of our aggregated secured and unsecured notes by $127.1 million and also reduced future interest payments.
proceeds from the Convertible Senior Notes offering.
Analysis of Cash Flow Changes
The following table summarizes our cash flows for the periods indicated:
| | | | Six Months Ended June 30, | | Three Months Ended March 31, |
| (in thousands) | 2020 | | 2019 | (in thousands) | 2021 | | 2020 |
| Net cash provided by operating activities | $ | 84,503 |
| | $ | 280,194 |
| Net cash provided by operating activities | $ | 72,346 | | | $ | 100,818 | |
| Net cash used in investing activities | (277,050 | ) | | (458,520 | ) | Net cash used in investing activities | (46,598) | | | (166,976) | |
| Net cash provided by financing activities | 189,558 |
| | 188,643 |
| |
| Net cash (used in) provided by financing activities | | Net cash (used in) provided by financing activities | (20,609) | | | 59,792 | |
For the sixthree months ended June 30, 2020,March 31, 2021, we generated $84.5$72.3 million of cash from operating activities, a decrease of $195.7$28.5 million from the same period in 2019.2020. 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 fromon derivatives, and the timing of supplier paymentsour receivable collections during the six three
months ended June 30, 2020.March 31, 2021. These declining factors were partially offset by higher realized prices for all commodities, lower lease operating expenses, production taxes, cash G&A and the timing of our receivable collectionssupplier payments for the sixthree months ended June 30, 2020March 31, 2021 as compared to the same 20192020 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 sixthree months ended June 30,March 31, 2021, cash flows from operating activities and net proceeds from the issuance of the Convertible Senior Notes were used to finance $46.2 million of drilling and development cash expenditures, repay net borrowings of $170.0 million under our credit facility and to fund $14.7 million in capped call spread transactions.
During the three months ended March 31, 2020, cash flows from operating activities, cash on hand, and net borrowings of $195.0$60.0 million under our credit facility were used to finance $271.4$161.9 million of drilling and development capex,cash expenditures and to fund $6.1$5.8 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.acquisitions.
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,March 31, 2021, we had $370.0$160.0 million in borrowings outstanding and $290.0$503.9 million in available borrowing capacity, which was net of $8.2$4.3 million in letters of credit outstanding and the availability blocker of $31.8 million. In connection with the Credit Agreement’s spring 2021 semi-annual borrowing base redetermination, the borrowing base and amount of elected commitments were reaffirmed at $700.0 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 Q2 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 applicable financial ratios described above as of June 30, 2020March 31, 2021 and through the filing of this Quarterly Report.
For further information on the Credit Agreement, refer to Note 4—3—Long-Term Debt under Part I, Item I of this Quarterly Report.
Convertible Senior Unsecured Note Debt Exchange and Senior Secured Notes
On May 22, 2020,March 19, 2021, CRP completed the Debt Exchange pursuant to which $110.6issued $150.0 million in aggregate principal amount of CRP’s 2026Convertible Senior Notes. On March 26, 2021, CRP issued an additional $20.0 million of Convertible Senior Notes and $143.7 million aggregate principal amountpursuant to the exercise of CRP’s 2027the underwriters’ over-allotment option to purchase additional Convertible 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 Convertible Senior Secured Notes bear interest at an annual rate of 8%3.25% and are due on JuneApril 1, 2025.2028. Interest is payable semi-annually in arrears on each JuneApril 1 and DecemberOctober 1, commencing on DecemberOctober 1, 2020.2021. CRP can settle the Convertible Senior Notes by paying or delivering cash, shares of the Company’s Class A common stock (the “Common Stock”), or a combination of cash and Common Stock, at CRP’s election.
The Debt Exchange was accounted for as a troubled debt restructuring in accordance with ASC 470-60. Thus, the carrying value of theConvertible 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.outstanding Senior Unsecured Notes as defined below.
Senior Notes
On November 30, 2017, CRP issued $400.0 million of 5.375% senior notes due 2026 (the “2026 Senior Notes”) and on March 15, 2019, CRP issued $500.0 million of 6.875% senior notes due 2027 (the “2027 Senior Notes” and, together with the 2026 Senior Notes, the “Senior Unsecured Notes”) in 144A private placements. In May 2020, a portion$110.6 million aggregate principal amount of the 2026 Senior Notes and $143.7 million aggregate principal amount of the 2027 Senior Notes were validly tendered and exchanged by certain eligible bondholders for consideration consisting of $127.1 million aggregate principal amount of 8.00% second lien senior secured notes due (the “Senior Secured Notes”).
The Senior Unsecured Notes were exchanged for Senior Secured Notes (see above discussion for detailsare fully and unconditionally guaranteed on a senior unsecured basis by Centennial and each of the exchange).CRP’s current subsidiaries that guarantee CRP’s revolving credit facility.
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, 2020March 31, 2021 and through the filing of this Quarterly Report.
For further information on any of our Convertible Senior Notes issuances,and Senior Notes, refer to Note 4—3—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, 2019,2020, 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 Convertible Senior Unsecured Notes as a result of the Debt Exchange discussed above. Refer to Note 13—12—Leases under Part I, Item I of this Quarterly Report for updated contractual obligations associated with our operating leases as of June 30, 2020.March 31, 2021.
Critical Accounting Policies and Estimates
There have been no material changes during the sixthree months ended June 30, 2020March 31, 2021 to the critical accounting policies previously disclosed in our 20192020 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 20192020 Annual Report for a discussion of our critical accounting policies and estimates.
New Accounting Pronouncements
There were no significantPlease refer to Note 1—Basis of Presentation and Summary of Significant Accounting Policies under Part I, Item 1. of this Quarterly Report for a discussion of recently adopted accounting standards and the potential effects of new accounting standards adopted or new accounting pronouncements that would have a potential effect on us aspronouncements.
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 halfthree months of 2020,2021, our oil and gas sales for the sixthree months ended June 30, 2020March 31, 2021 would have moved up or down $24.4$13.4 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$3.5 million for each 10% change in natural gas prices per Mcf.
Due to this volatility, we have historically used, and we may elect to continue to selectively use, commodity derivative instruments (such as collars, swaps and basis swaps) to mitigate price risk associated with a portion of our anticipated production. Our derivative instruments allow us to reduce, but not eliminate, the potential effects of the variability in cash flows from operations due to fluctuations in oil and natural gas prices and thereby provide increased certainty of cash flows for our drilling program and debt service requirements. These instruments provide only partial price protection against declines in oil and natural gas prices, but alternatively they may partially limit our potential gains from future increases in prices. Our credit agreementCredit Agreement limits our ability to enter into commodity hedges covering greater than 85% of our reasonably anticipated projected production from proved properties.
The following table below summarizes the terms of the swapderivative contracts we had in place as of June 30, 2020March 31, 2021 and additional contracts entered into through July 31, 2020.April 30, 2021. Refer to Note 7—6—Derivative Instruments in Item 1 of Part I of this Quarterly Report for open derivative positions as of June 30, 2020:March 31, 2021.
| | | | | | | | | | | | | | | | | | | | | | | | | |
| Period | | | | Volume (Bbls) | | Volume
(Bbls/d) | | Wtd. Avg. Crude Price ($/Bbl)(1) |
| Crude oil swaps | | | | | | | | | |
| NYMEX WTI | April 2021 - June 2021 | | | | 1,183,000 | | | 13,000 | | | $43.18 |
| July 2021 - September 2021 | | | | 736,000 | | | 8,000 | | | 45.87 |
| October 2021 - December 2021 | | | | 644,000 | | | 7,000 | | | 45.59 |
| January 2022 - March 2022 | | | | 45,000 | | | 500 | | | 60.72 |
| | | | | | | | | |
| | | | | | | | | |
| ICE Brent | April 2021 - June 2021 | | | | 409,500 | | | 4,500 | | | $54.98 |
| July 2021 - September 2021 | | | | 184,000 | | | 2,000 | | | 48.25 |
| October 2021 - December 2021 | | | | 184,000 | | | 2,000 | | | 48.50 |
| | | | | | | | | |
| | | | | | | | | |
|
| | | | | | | | | | | |
| | Period | | Volume (Bbls) | | Volume
(Bbls/d) | | Weighted Average Fixed Price ($/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 - $44.50 |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Period | | Volume (Bbls) | | Volume
(Bbls/d) | | Wtd. Avg. Collar Price Ranges ($/Bbl)(2) |
| Crude oil collars | April 2021 - June 2021 | | 227,500 | | | 2,500 | | | $42.00 | - | $51.14 |
| July 2021 - September 2021 | | 138,000 | | | 1,500 | | | 46.33 | - | 55.40 |
| October 2021 - December 2021 | | 92,000 | | | 1,000 | | | 42.00 | - | 50.10 |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| Period | | | | Volume (Bbls) | | Volume
(Bbls/d) | | Wtd. Avg. Differential ($/Bbl)(3) |
| Crude oil differential basis swaps | April 2021 - June 2021 | | | | 1,183,000 | | | 13,000 | | | $0.11 |
| July 2021 - September 2021 | | | | 736,000 | | | 8,000 | | | 0.26 |
| October 2021 - December 2021 | | | | 644,000 | | | 7,000 | | | 0.26 |
| | | | | | | | | |
| | | | | | | | | |
(1) These crude oil swap transactions are settled based on either the NYMEX WTI or ICE Brent index price, as applicable, on each trading day within the specified monthly settlement period versus the contractual swap price for the volumes stipulated.
(2) These crude oil collars are settled based on the NYMEX WTI price on each trading day within the specified monthly settlement period versus the contractual floor and ceiling prices for the volumes stipulated.
(3) These oil basis swap transactions are settled based on the difference between the arithmetic average of ARGUS MIDLAND WTI and ARGUS WTI CUSHING indices, during each applicable monthly settlement period.
| | | | | | | | | | | | | | | | | | | | | | | |
| Period | | Volume (MMBtu) | | Volume (MMBtu/d) | | Wtd. Avg. Gas Price ($/MMBtu)(1) |
| Natural gas swaps | April 2021 - June 2021 | | 3,640,000 | | | 40,000 | | | $2.89 |
| July 2021 - September 2021 | | 3,680,000 | | | 40,000 | | | 2.89 |
| October 2021 - December 2021 | | 3,680,000 | | | 40,000 | | | 2.95 |
| January 2022 - March 2022 | | 1,800,000 | | | 20,000 | | | 3.00 |
| | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | |
| Period | | Volume (MMBtu) | | Volume (MMBtu/d) | | Wtd. Avg. Differential ($/MMBtu)(2) |
| Natural gas basis differential swaps | April 2021 - June 2021 | | 3,640,000 | | | 40,000 | | | $(0.30) |
| July 2021 - September 2021 | | 3,680,000 | | | 40,000 | | | (0.30) |
| October 2021 - December 2021 | | 3,680,000 | | | 40,000 | | | (0.28) |
| January 2022 - March 2022 | | 1,800,000 | | | 20,000 | | | (0.26) |
| | | | | | | |
| |
(1)
| These crude oil swap transactions are settled based on the NYMEX WTI or ICE Brent oil price on each trading day within the specified monthly settlement period. |
| |
(2)
| These oil basis swap transactions are settled based on the difference between the arithmetic average of ARGUS MIDLAND WTI and ARGUS WTI CUSHING indices, during each applicable settlement period. |
| |
(3)
| These crude oil collars are settled based on the NYMEX WTI price on each trading day within the specified monthly settlement period and establish floor and ceiling prices for the contractual volumes. |
|
| | | | | | | | | | | |
| Period | | Volume (MMBtu) | | Volume (MMBtu/d) | | Weighted Average Fixed Price ($/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)(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 versus the contractual swap price for the volumes stipulated. (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 monthly settlement period. | 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, 20192020 to June 30, 2020,March 31, 2021, 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 | ) |
| | | | | | | | |
| (in thousands) | | Commodity derivative asset (liability) |
| Net fair value of oil and gas derivative contracts outstanding as of December 31, 2020 | | $ | (18,209) | |
| Commodity hedge contract settlement payments, net of any receipts | | 22,886 | |
Cash and non-cash mark-to-market losses on commodity hedge contracts(1) | At inception, new | (51,199) | |
Net fair value of oil and gas derivative contracts entered into by us have no intrinsic value.outstanding as of March 31, 2021 | | $ | (46,522) | |
(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, 2020March 31, 2021 would cause a $13.8$21.9 million increase or $22.2 million decrease, respectively, in this fair value liability,position, and a hypothetical upward or downward shift of 10% per Mcf in the NYMEX forward curve for natural gas as of June 30, 2020March 31, 2021 would cause a $1.3$3.1 million increase or decrease, respectively, in this same fair value liability.position.
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 (subject to a 1% floor), which exposes us to interest rate risk on our borrowings outstanding to the extent LIBOR increases.increases above the floor and we have borrowings outstanding. Further, LIBOR rates are expected to no longer be published beginning June 30,2023, however, due to the structure of the Credit Agreement, we do not expect the termination of LIBOR rates to have a material impact to us.
As of June 30, 2020,March 31, 2021, we had $370.0$160.0 million of debt outstanding under our credit agreement,Credit Agreement, with a weighted average interest rate of 3.5%3.0%. 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$1.6 million per year. We do not currently have or intend to enter into any derivative arrangementshedge contracts to protect against fluctuations in interest rates applicable to our outstanding indebtedness.
The remaining long-term debt balance of $736.0$903.8 million consists of our Senior Notes, which have fixed interest rates. Therefore,rates; therefore, this balance is not affected by interest rate movements. For additional information regarding our debt instruments, see Note 4—3—Long-Term Debt, in Item 1 of Part I of this Quarterly Report.
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.March 31, 2021. 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, 2020March 31, 2021 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, 2020March 31, 2021 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 timeRefer to time, we are party to ongoingin Item 1, Note 10—Commitments and Contingencies under Part I, Item 1. of this Quarterly Report for more information regarding our 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.proceedings.
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 20192020 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.filings. 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, There 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
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 reductionbeen no material changes 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 resultrisk factors from those described 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 20192020 Annual Report is the current market valueor our SEC filings.
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
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.Contents
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.
Item 6. Exhibits
|
| | | | | | | |
Exhibit
Number | | Description of Exhibit |
| 3.1 | | |
| 3.2 | | |
| 3.3 | | |
| 3.4 | | |
| 3.5 | | |
| 3.6 | | |
| 4.1 | | |
4.2 | | Indenture, dated as of May 22, 2020, by and among CRP, the guarantors party theretoMarch 19, 2021, between Centennial Resource Production, LLC and UMB Bank, N.A., asa trustee and collateral agent (incorporated by reference to Exhibit 4.1 to the Company’sCompany's Current Report on Form 8-K as filed with the SEC on May 22, 2020)March 19, 2021). |
4.34.2 | | First Supplemental Indenture, (2026 Senior Notes), dated as of May 22, 2020,March 19, 2021, between Centennial Resource Development, Inc., as parentProduction, LLC, the guarantor parties thereto, and UMB Bank, N.A., asa trustee (incorporated by reference to Exhibit 4.2 to the Company’sCompany's Current Report on Form 8-K as filed with the SEC on May 22, 2020)March 19, 2021). |
4.410.1 | | First Supplemental Indenture (2027 Senior Notes),Base Capped Call Transaction, dated as of May 22, 2020, between Centennial Resource Development, Inc., as parent guarantor, and UMB Bank, N.A., as trustee (incorporated by reference to Exhibit 4.3 the Company’s Current Report on Form 8-K filed with the SEC on May 22, 2020). |
10.1# | | |
10.2 | | Amendment no. 1 to Purchase and Sale Agreement, dated as of August 2, 2018,March 16, 2021, between Centennial Resource Production, LLC, Centennial Resource Development, Inc, and BP North America Inc.JPMorgan Chase Bank, National Association (incorporated by reference to Exhibit 10.1 to the Registrant’sCompany's Current Report on Form 8-K as filed with the SEC on March 31, 2020)19, 2021). |
10.3#10.2 | | |
| 10.3 | | |
| 10.4 | | SecondLimited Consent and Fifth Amendment to Second Amended and Restated Credit Agreement, dated as of May 1, 2020, amongMarch 15, 2021, between Centennial Resource Production, LLC, the guarantor parties thereto, and Lenders party thereto; JP Morgan Chase Bank, N.A, as borrower, administrative agent for the Lenders (incorporated by reference to Exhibit 10.4 to the Company's Current Report on Form 8-K as filed with the SEC on March 19, 2021). |
| 10.5# | | |
10.531.1* | | Third Amendment to Second Amended and Restated Credit Agreement and First Amendment to Second Amended and Restated Pledge and Security Agreement, dated as of May 1, 2020, among Centennial Resource Production, LLC, as borrower, Centennial Resource Development, Inc., as parent guarantor, the other guarantors party thereto, JPMorgan Chase Bank, N.A., as administrative agent and the lenders party thereto (incorporated by reference to Exhibit 10.2 to the Registrant’s Current Report on Form 8-K filed with the SEC on May 4, 2020). |
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. |
|
| 101.PRE* | | |
101.PRE* | | Inline XBRL Taxonomy Extension Presentation Linkbase Document. |
# Management contract or compensatory plan or agreement.
* Filed herewith.
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. |
| | |
| CENTENNIAL RESOURCE DEVELOPMENT, INC. |
| By: | | |
| By: | /s/ GEORGE S. GLYPHIS |
| | George S. Glyphis Vice President, Chief Financial Officer and Assistant Secretary |
| | |
| Date: | August 3, 2020May 5, 2021 |