UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
ý QUARTERLY REPORT PURSUANT TO SECTION☒Quarterly report pursuant to Section 13 ORor 15(d) OF THE SECURITIES EXCHANGE ACT OFof the Securities Exchange Act of 1934
For the quarterly period ended September 30, 2017March 31, 2022
OR
o TRANSITION REPORT PURSUANT TO SECTION☐Transition report pursuant to Section 13 ORor 15(d) OF THE SECURITIES EXCHANGE ACT OFof 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 Number) |
| | |
1001 Seventeenth Street, Suite 1800, Denver, Colorado | | 80202 |
(Address of Principal Executive Offices) | | (Zip Code)No.) |
1001 Seventeenth Street, Suite 1800
Denver, Colorado 80202
(Registrant’s telephone number, including area code): (720) 499-1400
(Registrant’s Telephone Number, Including Area Code)Securities registered pursuant to Section 12(b) of the Act:
| | | | | | | | | | | | | | |
| Title of each class | | Trading Symbol(s) | | Name of each exchange on which registered |
| 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 ý☒ No o☐
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes ý☒ No o☐
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 filero | | Accelerated filero | | Non-accelerated filerý (Do not check if a smaller reporting company)
| | Smaller reporting company o | | Emerging growth companyý |
| ☒ | | ☐ | | ☐ | | ☐ | | ☐ |
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. o☐
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes o☐ No ý☒
As of October 31, 2017,April 30, 2022, there were 256,731,091284,992,650 shares of Class A Common Stock, par value $0.0001 per share and 19,155,921 shares of Class C 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.
Bbls/Bbl/d. BarrelsOne 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. InstallationThe process of preparing an oil and gas wellbore for production through the installation of permanent production equipment, for productionas well as perforation and fracture stimulation to initiate production.
Development well. A well drilled within the proved area of an oil or natural gas or, inreservoir to the casedepth of a dry well,stratigraphic horizon known to reporting to the appropriate authority that the well has been abandoned.be productive.
Development project. The means by which petroleum resources are brought to the status of economically producible. As examples, the development of a single reservoir or field, an incremental development in a producing field or the integrated development of a group of several fields and associated facilities with a common ownership may constitute a development project.
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.
DryExploratory well. A well drilled to find a new field or to find a new reservoir in a field previously found to be incapableproductive of producing hydrocarbonsoil or natural gas in sufficient quantities such that proceeds fromanother reservoir.
Extension Well. A well drilled to extend the salelimits of such production exceed production expenses and taxes.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 on line.
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.
MBblsICE 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. HydrocarbonsThese are naturally occurring substances found in natural gas, which may be extracted as liquefied petroleum gasincluding ethane, butane, isobutane, propane and natural gasoline.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.
Realized price. The cash market price less all expected quality, transportation and demand adjustments.differentials.
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. Reserves should not be assigned to adjacent reservoirs isolated by major, potentially sealing, faults until those reservoirs are penetrated and evaluated as economically producible. Reserves should not be assigned to areas that are clearly separated from a known accumulation by a non-productive reservoir (i.e., absence of reservoir, structurally low reservoir or negative test results). Such areas may contain prospective resources (i.e., potentially recoverable resources from undiscovered accumulations).
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.
SOFR. Secured Overnight Funding Rate.
Spot market price. The cash market price without reduction for expected quality, location, transportation and demand adjustments.
Working interestUnproved reserves. Reserves attributable to unproved properties with no proved reserves.
Wellbore. The right granted to the lessee ofhole drilled by a property to develop and produce and own natural gas or other minerals. The working interest owners bear the exploration, development and operating costs on either a cash, penalty or carried basis.
WTI. West Texas Intermediate.
GLOSSARY OF CERTAIN OTHER TERMS
The following are definitions of certain other termsdrill bit that are used in this Quarterly Report on Form 10-Q:
Business Combination. The acquisition of approximately 89% of the outstanding membership interests in CRP from the Centennial Contributors, which closed on October 11, 2016, and the other transactions contemplated by the Contribution Agreement.
Celero. Celero Energy Company, LP, a Delaware limited partnership.
Centennial Contributors. CRD, NGP Follow-On and Celero, collectively.
The Company, we, our or us. (i) Centennial Resource Development, Inc. and its 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.
CRD. Centennial Resource Development, LLC, a Delaware limited liability company.
CRP. Centennial Resource Production, LLC, a Delaware limited liability company.
GMT Acquisition. Our acquisition of certain undeveloped acreage and producingis equipped for oil and natural gas properties of GMT Exploration Company LLC, which closedproduction 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 June 8, 2017.
IPO. Our initial public offering of units, which closed on February 29, 2016.
NewCo. New Centennial, LLC,the property and to a Delaware limited liability company controlled by affiliates of Riverstone.
NGP Follow-On. NGP Centennial Follow-On LLC, a Delaware limited liability company.
Private Placement Warrants. Our 8,000,000 outstanding warrants for the purchase of shares of Class A Common Stock, which were purchased by our Sponsor in a private placement simultaneously with the closing of our IPO.
Public Warrants. Warrants for the purchase of shares of Class A Common Stock sold as part of the Units in our IPO, all of which have been exercised or redeemed and are no longer outstanding.
Riverstone. Riverstone Investment Group LLC and its affiliates, including our Sponsor, collectively.
Series B Preferred Stock. Our Series B Preferred Stock, par value $0.0001 per share, all outstanding shares of which were converted into 26,100,000 shares of Class A Common Stock on May 25, 2017.
Silverback. Silverback Exploration, LLC and Silverback Operating, LLC, collectively.
Silverback Acquisition. Our acquisition of leasehold interests and related upstream assets in Reeves County, Texas from Silverback, which closed on December 28, 2016.
Sponsor. Our sponsor, Silver Run Sponsor, LLC, a Delaware limited liability company and an affiliate of Riverstone.
Units. Our units sold in our IPO, each of which consisted of one share of Class A Common Stockproduction, subject to all royalties and one-thirdother burdens and to all costs of one Public Warrant.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.
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 report,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 Form 10-Q,Quarterly Report, the words ”could,“could,” “may,” “believe,” “anticipate,” “intend,” “estimate,” “expect,” “project”“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'smanagement’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 Item 1A. Risk Factors”Factors in this Quarterly Report and in our Annual Report on Form 10-K for the year ended December 31, 2016 (“20162021 (the “2021 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 Coronavirus Disease 2019 (“COVID-19”) pandemic and the actions by certain oil and natural gas producing countries;
•political and economic conditions in or affecting other producing regions or countries, including the Middle East, Russia, Eastern Europe, Africa and South America;
•our business strategy; strategy and future drilling plans;
•our reserves;
our drilling prospects, inventories, projectsreserves and programs;
our ability to replace the reserves we produce through drilling and property acquisitions;
•our drilling prospects, inventories, projects and programs;
•our financial strategy, leverage, 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 future drilling plans;
•our competition and government regulations;
•our ability to obtain permits and governmental approvals;
•our pending legal or environmental matters;
our•the marketing and transportation of our oil, natural gas and NGLs;
•our leasehold or business acquisitions;
our costs•cost of developing or operating 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 Form 10-QQuarterly Report that are not historical.
All forward-looking statements speak only as of the date of this Form 10-Q. 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 our 20162021 Annual Report. Moreover, we operate in a very competitive and rapidly changing environment. New risks emerge from time to time. It is not possible for our management to predict all risks, nor can we assess the impact of all factors on our business or the extent to which any factor, or combination of factors, may cause actual results to differ materially from those contained in any forward-looking statements we may make.
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, intentions2021 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 Form 10-Q 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 Form 10-QQuarterly 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.
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 Form 10-Q.Quarterly Report.
PART I. FINANCIAL INFORMATION
Item 1. Financial Statements
CENTENNIAL RESOURCE DEVELOPMENT, INC.
CONDENSED CONSOLIDATED BALANCE SHEETS (unaudited)
(in thousands, except share and per share amounts)
|
| | | | | | | |
| | September 30, 2017 | | December 31, 2016 |
| ASSETS | | | |
| Current assets | | | |
| Cash and cash equivalents | $ | 2,581 |
| | $ | 134,083 |
|
| Accounts receivable, net | 50,207 |
| | 14,734 |
|
| Derivative instruments | 383 |
| | 431 |
|
| Prepaid and other current assets | 6,104 |
| | 2,078 |
|
| Total current assets | 59,275 |
| | 151,326 |
|
| Oil and natural gas properties, successful efforts method | | | |
| Unproved properties | 2,008,902 |
| | 1,905,661 |
|
| Proved properties | 1,306,873 |
| | 605,853 |
|
| Accumulated depreciation, depletion and amortization | (115,343 | ) | | (14,436) |
|
| Total oil and natural gas properties, net | 3,200,432 |
| | 2,497,078 |
|
| Other property and equipment, net | 3,897 |
| | 2,193 |
|
| Total property and equipment, net | 3,204,329 |
| | 2,499,271 |
|
| Noncurrent assets | | | |
| Derivative instruments | 242 |
| | — |
|
| Other noncurrent assets | 10,766 |
| | 1,045 |
|
| Total assets | $ | 3,274,612 |
| | $ | 2,651,642 |
|
| LIABILITIES AND SHAREHOLDERS’ EQUITY | | | |
| Current liabilities | | | |
| Accounts payable and accrued expenses | $ | 136,495 |
| | $ | 86,100 |
|
| Derivative instruments | 450 |
| | 5,361 |
|
| Total current liabilities | 136,945 |
| | 91,461 |
|
| Noncurrent liabilities | | | |
| Revolving credit facility | 165,000 |
| | — |
|
| Asset retirement obligations | 9,328 |
| | 7,226 |
|
| Deferred tax liability | 17,302 |
| | — |
|
| Derivative instruments | — |
| | 20 |
|
| Total liabilities | 328,575 |
| | 98,707 |
|
| Shareholders’ equity | | | |
| Preferred stock, $0.0001 par value, 1,000,000 shares authorized: | | | |
| Series A: 1 share issued and outstanding | — |
| | — |
|
| Series B: no shares issued and outstanding at September 30, 2017 and 104,400 shares issued and outstanding at December 31, 2016 | — |
| | — |
|
| Common stock, $0.0001 par value, 620,000,000 shares authorized: | | | |
| Class A: 257,760,091 shares issued and 256,670,839 shares outstanding at September 30, 2017 and 201,091,646 shares issued and 200,835,049 shares outstanding at December 31, 2016 | 26 |
| | 20 |
|
| Class C: 19,155,921 shares issued and outstanding | 2 |
| | 2 |
|
| Additional paid-in capital | 2,704,298 |
| | 2,364,049 |
|
| Retained earnings (accumulated deficit) | 36,103 |
| | (8,929 | ) |
| Total shareholders’ equity | 2,740,429 |
| | 2,355,142 |
|
| Noncontrolling interest | 205,608 |
| | 197,793 |
|
| Total equity | 2,946,037 |
| | 2,552,935 |
|
| Total liabilities and shareholders’ equity | $ | 3,274,612 |
| | $ | 2,651,642 |
|
| | | | | | | | | | | |
| March 31, 2022 | | December 31, 2021 |
| ASSETS | | | |
| Current assets | | | |
| Cash and cash equivalents | $ | 50,624 | | | $ | 9,380 | |
| Accounts receivable, net | 131,837 | | | 71,295 | |
| Prepaid and other current assets | 6,973 | | | 5,860 | |
| Total current assets | 189,434 | | | 86,535 | |
| Property and Equipment | | | |
| Oil and natural gas properties, successful efforts method | | | |
| Unproved properties | 1,032,096 | | | 1,040,386 |
| Proved properties | 4,742,872 | | | 4,623,726 |
| Accumulated depreciation, depletion and amortization | (2,059,679) | | | (1,989,489) |
| Total oil and natural gas properties, net | 3,715,289 | | | 3,674,623 |
| Other property and equipment, net | 11,774 | | | 11,197 |
| Total property and equipment, net | 3,727,063 | | | 3,685,820 | |
| Noncurrent assets | | | |
| Operating lease right-of-use assets | 14,714 | | | 16,385 | |
| Other noncurrent assets | 27,321 | | | 15,854 |
| TOTAL ASSETS | $ | 3,958,532 | | | $ | 3,804,594 | |
| LIABILITIES AND EQUITY | | | |
| Current liabilities | | | |
| Accounts payable and accrued expenses | $ | 178,940 | | | $ | 130,256 | |
| Operating lease liabilities | 1,728 | | | 1,413 | |
| Derivative instruments | 117,689 | | | 35,150 | |
| Other current liabilities | 1,370 | | | 1,080 | |
| Total current liabilities | 299,727 | | | 167,899 |
| Noncurrent liabilities | | | |
| Long-term debt, net | 801,203 | | | 825,565 | |
| Asset retirement obligations | 17,647 | | | 17,240 | |
| Deferred income taxes | 8,834 | | | 2,589 | |
| Operating lease liabilities | 14,473 | | | 16,002 | |
| Other noncurrent liabilities | 45,571 | | | 24,579 | |
| Total liabilities | 1,187,455 | | | 1,053,874 |
| Commitments and contingencies (Note 11) | 0 | | 0 |
| Shareholders’ equity | | | |
| Common stock, $0.0001 par value, 620,000,000 shares authorized; 294,135,384 shares issued and 284,991,150 shares outstanding at March 31, 2022 and 294,260,623 shares issued and 284,696,972 shares outstanding at December 31, 2021 | 29 | | | 29 | |
| Additional paid-in capital | 3,017,572 | | | 3,013,017 | |
| Retained earnings (accumulated deficit) | (246,524) | | | (262,326) | |
| Total Shareholders' equity | 2,771,077 | | | 2,750,720 | |
| TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY | $ | 3,958,532 | | | $ | 3,804,594 | |
The accompanying notes are an integral part of these unaudited condensed consolidated financial statements.
CENTENNIAL RESOURCE DEVELOPMENT, INC.
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS (unaudited)
(in thousands, except per share data)
| | | | | | | | | | | | | | | | | | Three Months Ended March 31, | |
| | Successor | | | Predecessor | | Successor | | | Predecessor | | 2022 | | 2021 | |
| | For the Three Months Ended September 30, 2017 | | | For the Three Months Ended September 30, 2016 | | For the Nine Months Ended September 30, 2017 | | | For the Nine Months Ended September 30, 2016 | |
| Net revenues | | | | | | | | | | |
| Oil sales | $ | 87,286 |
| | | $ | 23,388 |
| | $ | 204,702 |
| | | $ | 56,975 |
| |
| Natural gas sales | 12,852 |
| | | 2,629 |
| | 33,226 |
| | | 5,717 |
| |
| NGL sales | 11,473 |
| | | 1,304 |
| | 25,844 |
| | | 3,097 |
| |
| Total net revenues | 111,611 |
| | | 27,321 |
| | 263,772 |
| | | 65,789 |
| |
| Operating revenues | | Operating revenues | | | | |
| Oil and gas sales | | Oil and gas sales | $ | 347,277 | | | $ | 192,391 | | |
| Operating expenses | | | | | | | | | | Operating expenses | | |
| Lease operating expenses | 11,373 |
| | | 3,656 |
| | 26,924 |
| | | 10,295 |
| Lease operating expenses | 28,734 | | | 25,861 | | |
| Severance and ad valorem taxes | 6,448 |
| | | 1,432 |
| | 14,358 |
| | | 3,523 |
| Severance and ad valorem taxes | 25,051 | | | 12,583 | | |
| Gathering, processing and transportation expenses | 9,925 |
| | | 1,787 |
| | 22,572 |
| | | 4,375 |
| Gathering, processing and transportation expenses | 21,891 | | | 20,625 | | |
| Depreciation, depletion and amortization | 42,387 |
| | | 18,454 |
| | 102,847 |
| | | 60,939 |
| Depreciation, depletion and amortization | 71,009 | | | 63,783 | | |
| Impairment and abandonment expenses | — |
| | | 1,649 |
| | (29 | ) | | | 2,546 |
| |
| Exploration expense | 1,622 |
| | | 402 |
| | 4,092 |
| | | 920 |
| |
| General and administrative expenses | 13,311 |
| | | 4,848 |
| | 36,017 |
| | | 9,735 |
| General and administrative expenses | 30,603 | | | 25,256 | | |
| Impairment and abandonment expense | | Impairment and abandonment expense | 2,627 | | | 9,200 | | |
| Exploration and other expenses | | Exploration and other expenses | 2,307 | | | 1,095 | | |
| Total operating expenses | 85,066 |
| | | 32,228 |
| | 206,781 |
| | | 92,333 |
| Total operating expenses | 182,222 | | | 158,403 | | |
| Total operating income (loss) | 26,545 |
| | | (4,907 | ) | | 56,991 |
| | | (26,544 | ) | |
| Net gain (loss) on sale of long-lived assets | | Net gain (loss) on sale of long-lived assets | 82 | | | 44 | | |
| | Income (loss) from operations | | Income (loss) from operations | 165,137 | | | 34,032 | | |
| | Other income (expense) | | | | | | | | | | Other income (expense) | | |
| Gain (loss) on sale of oil and natural gas properties | (141 | ) | | | 15 |
| | 7,216 |
| | | 11 |
| |
| Interest expense | (1,015 | ) | | | (1,983 | ) | | (2,132 | ) | | | (5,422 | ) | Interest expense | (13,154) | | | (17,485) | | |
| | Net gain (loss) on derivative instruments | (896 | ) | | | 1,741 |
| | 5,392 |
| | | (4,184 | ) | Net gain (loss) on derivative instruments | (129,523) | | | (51,199) | | |
| Other income | — |
| | | — |
| | — |
| | | 6 |
| |
| Other income (expense) | (2,052 | ) | | | (227 | ) | | 10,476 |
| | | (9,589 | ) | Other income (expense) | 118 | | | 7 | | |
| Total other income (expense) | | Total other income (expense) | (142,559) | | | (68,677) | | |
| | Income (loss) before income taxes | 24,493 |
| | | (5,134 | ) | | 67,467 |
| | | (36,133 | ) | Income (loss) before income taxes | 22,578 | | | (34,645) | | |
| Income tax (expense) benefit | (8,233 | ) | | | — |
| | (17,302 | ) | | | 406 |
| Income tax (expense) benefit | (6,776) | | | — | | |
| Net income (loss) | 16,260 |
| | | (5,134 | ) | | $ | 50,165 |
| | | $ | (35,727 | ) | Net income (loss) | $ | 15,802 | | | $ | (34,645) | | |
| Less: Net income attributable to noncontrolling interest | 1,813 |
| | | — |
| | 5,133 |
| | | — |
| |
| Net income (loss) attributable to common shareholders | $ | 14,447 |
| | | $ | (5,134 | ) | | $ | 45,032 |
| | | $ | (35,727 | ) | |
| Income per share: | | | | | | | | | | |
| | Income (loss) per share of Common Stock: | | Income (loss) per share of Common Stock: | | |
| Basic | $ | 0.06 |
| | | | | $ | 0.20 |
| | | | Basic | $ | 0.06 | | | $ | (0.12) | | |
| Diluted | $ | 0.06 |
| | | | | $ | 0.19 |
| | | | Diluted | $ | 0.05 | | | $ | (0.12) | | |
The accompanying notes are an integral part of these unaudited condensed consolidated financial statements.
CENTENNIAL RESOURCE DEVELOPMENT, INC.
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (unaudited)
(in thousands)
|
| | | | | | | | |
| | Successor | | | Predecessor |
| | For the Nine Months Ended September 30, 2017 | | | For the Nine Months Ended September 30, 2016 |
| Cash flows from operating activities: | | | | |
| Net income (loss) | $ | 50,165 |
| | | $ | (35,727 | ) |
| Adjustments to reconcile net income (loss) to net cash provided by operating activities: | | | | |
| Depreciation, depletion and amortization | 102,847 |
| | | 60,939 |
|
| Stock-based compensation expense | 9,420 |
| | | — |
|
| Impairment and abandonment expenses | (29 | ) | | | 2,546 |
|
| Deferred tax expense (benefit) | 17,302 |
| | | (406 | ) |
| (Gain) loss on sale of oil and natural gas properties | (7,216 | ) | | | (11 | ) |
| Non-cash portion of derivative (gain) loss | (5,126 | ) | | | 20,807 |
|
| Amortization of debt issuance costs | 348 |
| | | 363 |
|
| Changes in operating assets and liabilities: | | | | |
| (Increase) decrease in accounts receivable | (28,172 | ) | | | 3,021 |
|
| Increase in prepaid and other assets | (12,890 | ) | | | (165 | ) |
| Increase in accounts payable and other liabilities | 10,501 |
| | | 144 |
|
| Net cash provided by operating activities | 137,150 |
| | | 51,511 |
|
| Cash flows from investing activities: | | | | |
| Acquisition of oil and natural gas properties | (419,471 | ) | | | (55,566 | ) |
| Drilling and development capital expenditures | (354,515 | ) | | | (45,203 | ) |
| Purchases of other property and equipment | (3,482 | ) | | | (206 | ) |
| Proceeds from sales of oil and natural gas properties | 10,714 |
| | | — |
|
| Net cash used in investing activities | (766,754 | ) | | | (100,975 | ) |
| Cash flows from financing activities: | | | | |
| Issuance of Class A common shares | 340,750 |
| | | — |
|
| Underwriters discount and offering costs | (7,233 | ) | | | — |
|
| Proceeds from revolving credit facility | 190,000 |
| | | 55,000 |
|
| Repayment of revolving credit facility | (25,000 | ) | | | (5,000 | ) |
| Financing obligation | — |
| | | (1,894 | ) |
| Debt issuance costs | (415 | ) | | | — |
|
| Net cash provided by financing activities | 498,102 |
| | | 48,106 |
|
| Net decrease in cash and cash equivalents | (131,502 | ) | | | (1,358 | ) |
| Cash and cash equivalents, beginning of period | 134,083 |
| | | 1,768 |
|
| Cash and cash equivalents, end of period | $ | 2,581 |
| | | $ | 410 |
|
| Supplemental cash flow information | | | | |
| Cash paid for interest | $ | 1,915 |
| | | $ | 4,993 |
|
| Supplemental non-cash activity | | | | |
| Accrued capital expenditures included in accounts payable and accrued expenses | $ | 102,152 |
| | | $ | 16,339 |
|
| Asset retirement obligations incurred, including changes in estimate | $ | 1,016 |
| | | $ | 206 |
|
| | | | | | | | | | | |
| Three Months Ended March 31, |
| 2022 |
| 2021 |
| Cash flows from operating activities: | | | |
| Net income (loss) | $ | 15,802 | | | $ | (34,645) | |
| Adjustments to reconcile net income (loss) to net cash provided by operating activities: | | | |
| Depreciation, depletion and amortization | 71,009 | | | 63,783 | |
| Stock-based compensation expense - equity awards | 5,545 | | | 4,585 | |
| Stock-based compensation expense - liability awards | 13,720 | | | 10,414 | |
| Impairment and abandonment expense | 2,627 | | | 9,200 | |
| Deferred tax expense (benefit) | 6,776 | | | — | |
| Net (gain) loss on sale of long-lived assets | (82) | | | (44) | |
| Non-cash portion of derivative (gain) loss | 86,645 | | | 28,313 | |
| Amortization of debt issuance costs and debt discount | 1,492 | | | 1,847 | |
| | | |
| Changes in operating assets and liabilities: | | | |
| (Increase) decrease in accounts receivable | (53,824) | | | (14,997) | |
| (Increase) decrease in prepaid and other assets | (415) | | | (264) | |
| Increase (decrease) in accounts payable and other liabilities | 10,825 | | | 4,154 | |
| Net cash provided by operating activities | 160,120 | | | 72,346 | |
| Cash flows from investing activities: | | | |
| Acquisition of oil and natural gas properties | (1,928) | | | (433) | |
| Drilling and development capital expenditures | (81,156) | | | (46,152) | |
| Purchases of other property and equipment | (1,052) | | | (181) | |
| Proceeds from sales of oil and natural gas properties | 48 | | | 168 | |
| Net cash used in investing activities | (84,088) | | | (46,598) | |
| Cash flows from financing activities: | | | |
| | | |
| | | |
| Proceeds from borrowings under revolving credit facility | 135,000 | | | 70,000 | |
| Repayment of borrowings under revolving credit facility | (160,000) | | | (240,000) | |
| Proceeds from issuance of senior notes | — | | | 170,000 | |
| Debt issuance costs | (8,530) | | | (5,444) | |
| Premiums paid on capped call transactions | — | | | (14,688) | |
| | | |
| Proceeds from exercise of stock options | 1 | | | — | |
| Restricted stock used for tax withholdings | (1,259) | | | (477) | |
| Net cash used in financing activities | (34,788) | | | (20,609) | |
| Net increase (decrease) in cash, cash equivalents and restricted cash | 41,244 | | | 5,139 | |
| Cash, cash equivalents and restricted cash, beginning of period | 9,935 | | | 8,339 | |
| Cash, cash equivalents and restricted cash, end of period | $ | 51,179 | | | $ | 13,478 | |
The accompanying notes are an integral part of these unaudited condensed consolidated financial statements.
CENTENNIAL RESOURCE DEVELOPMENT, INC.
CONDENSED CONSOLIDATED STATEMENTSTATEMENTS OF SHAREHOLDERS’ EQUITYCASH FLOWS (unaudited)
(continued)
(in thousands)
| | | | | | | | | | | |
| Three Months Ended March 31, |
| 2022 |
| 2021 |
| Supplemental cash flow information | | | |
| Cash paid for interest | $ | 8,903 | | | $ | 11,272 | |
| Supplemental non-cash activity | | | |
| Accrued capital expenditures included in accounts payable and accrued expenses | $ | 63,483 | | | $ | 50,333 | |
| Asset retirement obligations incurred, including revisions to estimates | 145 | | | 24 | |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Common Stock | | Preferred Stock | | | | | | | | | | |
| | Class A | | Class C | | Series A | | Series B | | Additional Paid-In Capital | | Retained Earnings (Accumulated Deficit) | | Total Shareholders’ Equity | | Noncontrolling Interest | | Total Equity |
| | Shares | | Amount | | Shares | | Amount | | Shares | | Amount | | Shares | | Amount | | | | | |
| Balance at December 31, 2016 | 201,092 |
| | $ | 20 |
| | 19,156 |
| | $ | 2 |
| | — |
| | $ | — |
| | 104 |
| | $ | — |
| | $ | 2,364,049 |
| | $ | (8,929 | ) | | $ | 2,355,142 |
| | $ | 197,793 |
| | $ | 2,552,935 |
|
| Warrants exercised | 6,236 |
| | 1 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | (1 | ) | | — |
| | — |
| | — |
| | — |
|
| Restricted stock issued | 841 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
| Restricted stock forfeited | (9 | ) | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
| Conversion of Series B preferred shares to Class A common shares | 26,100 |
| | 3 |
| | — |
| | — |
| | — |
| | — |
| | (104 | ) | | — |
| | (3 | ) | | — |
| | — |
| | — |
| | — |
|
| Sale of unregistered Class A common shares | 23,500 |
| | 2 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 340,748 |
| | | | 340,750 |
| | — |
| | 340,750 |
|
| Underwriters' discount and offering expense | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | (7,233 | ) | | — |
| | (7,233 | ) | | — |
| | (7,233 | ) |
| Stock-based compensation | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 9,420 |
| | — |
| | 9,420 |
| |
| | 9,420 |
|
| Change in equity due to issuance of shares by Centennial Resource Production, LLC | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | (2,682 | ) | | — |
| | (2,682 | ) | | 2,682 |
| | — |
|
| Net income | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 45,032 |
| | 45,032 |
| | 5,133 |
| | 50,165 |
|
| Balance at September 30, 2017 | 257,760 |
| | $ | 26 |
| | 19,156 |
| | $ | 2 |
| | — |
| | $ | — |
| | — |
| | $ | — |
| | $ | 2,704,298 |
| | $ | 36,103 |
| | $ | 2,740,429 |
| | $ | 205,608 |
| | $ | 2,946,037 |
|
| | | | | | | | | | | |
| Three Months Ended March 31, |
| 2022 | | 2021 |
| Cash and cash equivalents | $ | 50,624 | | | $ | 10,936 | |
Restricted cash(1) | 555 | | | 2,542 | |
| Total cash, cash equivalents and restricted cash | $ | 51,179 | | | $ | 13,478 | |
(1) Included in Prepaid and other current assets in the consolidated balance sheet as of March 31, 2022.
The accompanying notes are an integral part of these unaudited condensed consolidated financial statements.
CENTENNIAL RESOURCE DEVELOPMENT, INC.
CONSOLIDATED STATEMENTS OF SHAREHOLDERS’ EQUITY (unaudited)
(in thousands)
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Common Stock | Additional Paid-In Capital | | Retained Earnings (Accumulated Deficit) | | Total Shareholders’ Equity |
| Shares | | Amount | | | |
| Balance at December 31, 2021 | 294,261 | | | $ | 29 | | | $ | 3,013,017 | | | $ | (262,326) | | | $ | 2,750,720 | |
| Restricted stock issued | 20 | | | — | | | — | | | — | | | — | |
| Restricted stock forfeited | (52) | | | — | | | — | | | — | | | — | |
| Restricted stock used for tax withholding | (150) | | | — | | | (1,259) | | | — | | | (1,259) | |
| Stock option exercises | 3 | | | — | | | 1 | | | — | | | 1 | |
| Issuance of Common Stock under Employee Stock Purchase Plan | 53 | | | — | | | 268 | | | — | | | 268 | |
| Stock-based compensation - equity awards | — | | | — | | | 5,545 | | | — | | | 5,545 | |
| Net income (loss) | — | | | — | | | — | | | 15,802 | | | 15,802 | |
| Balance at March 31, 2022 | 294,135 | | | 29 | | | $ | 3,017,572 | | | $ | (246,524) | | | $ | 2,771,077 | |
| | | | | | | | | |
| | | | | | | | | |
| | | | | | | | | |
| | | | | | | | | |
| | | | | | | | | |
| | | | | | | | | |
| | | | | | | | | |
| | | | | | | | | |
| | | | | | | | | |
| | | | | | | | | |
| | | | | | | | | |
| | | | | | | | | |
| | | | | | | | | |
| | | | | | | | | |
| | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | |
| | | | | | | |
| | | | | | |
| Balance at December 31, 2020 | 290,646 | | | $ | 29 | | | $ | 3,004,433 | | | $ | (400,501) | | | $ | 2,603,961 | |
| | | | | | | | | |
| Restricted stock forfeited | (1) | | | — | | | — | | | — | | | — | |
| Restricted stock used for tax withholding | (128) | | | — | | | (477) | | | — | | | (477) | |
| Issuance of Common Stock under Employee Stock Purchase Plan | 276 | | | — | | | 167 | | | — | | | 167 | |
| Stock-based compensation - equity awards | — | | | — | | | 4,585 | | | — | | | 4,585 | |
| Capped call premiums | — | | | — | | | (14,688) | | | — | | | (14,688) | |
| Net income (loss) | — | | | — | | | — | | | (34,645) | | | (34,645) | |
| Balance at March 31, 2021 | 290,793 | | | 29 | | | $ | 2,994,020 | | | $ | (435,146) | | | $ | 2,558,903 | |
| | | | | | | | | |
| | | | | | | | | |
| | | | | | | | | |
| | | | | | | | | |
| | | | | | | | | |
| | | | | | | | | |
| | | | | | | | | |
| | | | | | | | | |
| | | | | | | | | |
| | | | | | | | | |
| | | | | | | | | |
| | | | | | | | | |
| | | | | | | | | |
| | | | | | | | | |
| | | | | | | | | |
| | | | | | | | | |
The accompanying notes are an integral part of these unaudited consolidated financial statements.
CENTENNIAL RESOURCE DEVELOPMENT, INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
Note 1—Basis of Presentation and Summary of Significant Accounting Policies
Description of Business
Centennial Resource Development, Inc. (the “Company” or “Centennial”) was originally incorporated in Delaware on November 4, 2015 as a special purpose acquisition company under the name Silver Run Acquisition Corporation for the purpose of effecting a merger, capital stock exchange, asset acquisition, stock purchase, reorganization or similar business combination involving the Company and one or more businesses.
On February 29, 2016, the Company consummated its initial public offering of Units each consisting of one share of Class A Common Stock and one-third of one Public Warrant. On October 11, 2016, the Company consummated the acquisition of approximately 89% of the outstanding membership interests in Centennial Resource Production, LLC, a Delaware limited liability company (“CRP” and such acquisition, the “Business Combination”). In connection with the closing of the Business Combination, the Company changed its name from "Silver Run Acquisition Corporation" to "Centennial Resource Development, Inc."
CRP was formed in August 2012 byis an affiliate of NGP Energy Capital Management, a family of energy-focused private equity investment funds, in connection with the acquisition of all of the oil and natural gas properties and certain other assets of Celero, which was formed in 2006 to focus on the development and acquisition of oil and natural gas properties located primarily in the Permian Basin of West Texas. Until the closing of the Business Combination, CRP operated as a privately-held independent oil and natural gas company.
company focused on the development of crude 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 subsidiaries.subsidiary, Centennial Resource Production, LLC (“CRP”).
Principles of Consolidation and Basis of Presentation
The accompanying unaudited condensed consolidated financial statements have been prepared in accordance with generally accepted accounting principles in the United States of America (“U.S. GAAP”) and the rules and regulations of the SEC.United States Securities and Exchange Commission (“SEC”) for interim financial reporting. Accordingly, certain disclosures required by U.S. GAAP and normally included in an Annual Report on Form 10-K have been omitted. Although management believes that our disclosures in these interimThe consolidated financial statements are adequate, theyand related notes included in this Quarterly Report should be read in conjunction with our 2016the 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, 2021 (the “2021 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 2021 Annual Report.
In the opinion of management, all normal, recurring adjustments and accruals considered necessary for a fair presentation of interim financial information,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. Certain prior period amounts have been reclassified to conform to the current presentation on the accompanying condensed consolidated financial statements. The Company has evaluated subsequent events through the date of this filing.
As a result of the Business Combination, the Company is the acquirer for accounting purposes, and CRP is the acquiree and accounting Predecessor. The Company’s financial statement presentation distinguishes a “Predecessor” for CRP for periods prior to the Business Combination. The Company is the “Successor” for periods after the Business Combination, which includes consolidation of CRP subsequent to the Business Combination on October 11, 2016. The Business Combination was accounted for as a business combination using the acquisition method of accounting, and the Successor financial statements reflect a new basis of accounting that is based on the fair value of CRP’s net assets acquired. As a result of the application of the acquisition method of accounting as of the Business Combination, the financial statements for the Predecessor period and for the Successor period are presented on a different basis of accounting.
Principles of Consolidation
The consolidated financial statements include the accounts of the Company and its majority owned subsidiary CRP, and CRP’s wholly-owned subsidiaries. All intercompany balances and transactions have been eliminated in consolidation.
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 in 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.
CENTENNIAL RESOURCE DEVELOPMENT, INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
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 offor long-lived assets; (iii) impairment expense of unproved properties; (iv) depreciation, depletion and amortization; (iv)(v) asset retirement obligations; (v)(vi) determining fair value and allocating purchase price in connection with business combinations and asset acquisitions; (vi) valuation of derivative instruments; (vii) accrued revenuerevenues and related receivables; and (viii) accrued liabilities.liabilities; (ix) derivative valuations; (x) deferred income taxes; and (xi) determining the fair values of certain stock-based compensation awards.
Recently Issued Accounting StandardsLeases
In January 2017,The Company has operating leases for drilling rig contracts, office rental agreements, and other wellhead equipment. There were no significant changes in operating leases during the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2017-01, Business Combinations (Topic 805): Clarifyingthree months ended March 31, 2022. Refer to Note 15—Leases footnote in the Definition of a Business. This update affects all reporting entities andnotes to the objective of the guidance is to assist with evaluation of whether transactions should be accounted for as acquisitions (or disposals) of assets or businesses. The mandatory effective date for this update is forconsolidated financial statements issued for fiscal years beginning after December 15, 2017, including interim periods within those fiscal years. The amendments should be applied prospectively on or after the effective date and disclosures are not required at transition. Early adoption is permitted for transactions for which the acquisition date occurs before the issuance date or effective date of the amendments, only when the transaction has not been reported in financial statements that have been issued or made available for issuance. The Company early adopted ASU 2017-01 in the second quarter of 2017. Refer to Note 2—Property Acquisitions for details of the GMT Acquisition.
In August 2016, the FASB issued ASU 2016-15, Statement of Cash Flows: Classification of Certain Cash Receipts and Cash Payments. This update applies to all entities that are required to present a statement of cash flows. This update provides guidance on eight specific cash flow issues: debt prepayment or debt extinguishment costs, settlement of zero-coupon debt instruments or other debt instruments with coupon interest rates that are insignificant in relation to the effective interest rate of the borrowing, contingent consideration payments made after a business combination, proceeds from the settlement of insurance claims, proceeds from the settlement of corporate-owned life insurance policies, including bank-owned life insurance policies, distributions received from equity method investees, beneficial interests in securitization transactions and separately identifiable cash flows and application of the predominance principle. This update will be effective for financial statements issued for fiscal years beginning after December 31, 2017, including interim periods within those fiscal years with early adoption permitted. This update should be applied using the retrospective transition method. Adoption of this standard will only affect the presentationItem 8 of the Company’s statements of cash flows and will not have a material impact2021 Annual Report.
Income Taxes
Income tax expense recognized during interim periods is based on its consolidated financial statements.
In March 2016, the FASB issued ASU 2016-09, Compensation-Stock Compensation. This update applies to all entities that issue equity-based payment awards to their employees. Under this update, there were several areas that were simplified including theapplying an estimated annual effective income tax consequences, classification of awards as either equityrate to the Company’s year-to-date income, plus any significant unusual or liabilities and classification on the statement of cash flows. This update will be effective for financial statements issued for fiscal years beginning after December 15, 2016, including interim periods within those fiscal years with early adoption permitted. The Company elected to early adopt this guidance in October 2016 in conjunction with the issuance of its equity awards.
In February 2016, the FASB issued ASU 2016-02, Leases. This update applies to any entity that enters into a lease, with some specified scope exemptions. Under this update, a lessee should recognizeinfrequently occurring items which are recorded in the statementinterim period. The computation of financial position a liabilitythe annual estimated effective tax rate at each interim period requires certain estimates and significant judgment including, but not limited to, make lease payments (the lease liability) and a right-of-use asset representing its right to use the underlying assetexpected operating income for the lease term. While there were no major changes to the lessor accounting, changes were made to align key aspects with the revenue recognition guidance. This update will be effective for public entities for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years, with early adoption permitted. Entities will be required to recognize and measure leases at the beginningyear, projections of the earliest period presented using a modified retrospective approach. Althoughproportion of income earned and taxed in various state jurisdictions, permanent and temporary differences and the Company is still inlikelihood of recovering deferred tax assets generated. The accounting estimates used to compute the process of evaluatingprovision for income taxes may change as new events occur, additional information becomes known or as the effect of adopting ASU 2016-02, the adoption is expected to result in the recognition of assets and liabilities on its consolidated balance sheet for current operating leases. As of December 31, 2016, the Company had approximately $17.0 million of contractual obligations related to its non-cancelable leases, and it will evaluate those contracts as well as other existing arrangements to determine if they qualify for lease accounting under ASU 2016-02.
In May 2014, the FASB issued ASU No. 2014-09, Revenue from Contracts with Customers, which supersedes the revenue recognition requirements in ASC Topic 605, Revenue Recognition, and most industry-specific guidance. The FASB subsequently issued various ASUs which deferred the effective date of ASU 2014-09 and provided additional implementation guidance. ASU 2014-09 and its amendments provides companies with a single model for use in accounting for revenue arising from contracts with customers and supersedes current revenue recognition guidance, including industry-specific revenue guidance. The core principle of the model is to recognize revenue when control of the goods or services transfers to the customer, as opposed to recognizing revenue when the risks and rewards transfer to the customer under the existing revenue guidance. In addition, new qualitative and quantitative disclosure requirements aim to enable financial statement users to understand the nature, amount, timing and uncertainty of revenue and cash flows arising from contracts with customers. ASU 2014-09 and its amendments are effective for fiscal years, and interim periods within those years, beginning after December 15, 2017. The standards permit
tax environment changes.
CENTENNIAL RESOURCE DEVELOPMENT, INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
retrospective application using either of the following methodologies: (i) restatement of each prior reporting period presented or (ii) recognition of a cumulative-effect adjustment as of the date of initial application.
The Company does not expect net income or cash flows to be materially impacted by the new standard, however, the Company is currently analyzing whether changes to total revenues and total expenses will be necessary to properly reflect revenue for certain pipeline gathering, transportation and gas processing agreements. The Company continues to evaluate the expected disclosure requirements, changes to relevant business practices, accounting policies and control activities as a result of the adoption of the ASU and has not yet developed estimates of the quantitative impact to the Company's consolidated financial statements. The Company has selected the modified retrospective method and will adopt this guidance on the effective date of January 1, 2018.
Note 2—Property Acquisitions
2017 Acquisition
On June 8, 2017, the Company completed the GMT Acquisition and acquired interests in 36 producing horizontal wells plus undeveloped acreage on approximately 11,850 net acres (14,770 gross acres) in Lea County, New Mexico for an unadjusted purchase price of $350.0 million. The Company operates approximately 79% of, and has an approximate 85% average working interest in, this acreage. The acquired acres are located in the Northern Delaware Basin with drilling locations in the Avalon Shale, 2nd Bone Spring Sand, 3rd Bone Spring Sand and Wolfcamp A formations.
The GMT Acquisition was recorded as an asset acquisition under ASU 2017-01. Accordingly, the GMT purchase consideration has been allocated to the GMT oil and natural gas properties based on their relative fair values measured as of the acquisition date. After settlement statement adjustments of $0.9 million, the Company paid a net purchase price of $349.1 million. On a relative fair value basis, $296.2 million was allocated to unproved properties and $53.2 million to proved properties with the remaining purchase price allocated amongst other assets and liabilities. Transaction costs as they relate to the GMT Acquisition mainly consist of advisory, legal and accounting fees and are capitalized as incurred, and the Company has incurred $0.5 million in transaction costs related to this acquisition as of September 30, 2017.
2016 Acquisition
On December 28, 2016, the Company acquired interests in 31 producing horizontal wells plus undeveloped acreage on approximately 35,500 net acres (43,500 gross acres) in Reeves County, Texas for an unadjusted purchase price of $855.0 million, which consisted of cash consideration paid by the Company and a $32.3 million payable at December 31, 2016 that was settled in 2017 when title issues relating to the purchased acreage were satisfied. The Company operates approximately 90% of, and has an approximate 90% working interest in, this acreage. The Wolfcamp A and Wolfcamp B are producing horizons on this acreage, and the Company believes that this acreage may be prospective for the Wolfcamp C, Avalon and Bone Spring shale formations.
The Silverback Acquisition was recorded using the acquisition method of accounting for business combinations. The allocation of the purchase price is based upon management’s estimates and assumptions related to the fair value of assets acquired and liabilities assumedon the acquisition date using currently available information. Transaction costs relating to this purchase were expensed as incurred. The initial accounting for the Silverback Acquisition is preliminary, and adjustments to provisional amounts (such as certain accrued liabilities) or recognition of additional assets acquired or liabilities assumed, may occur as additional information is obtained about facts and circumstances that existed as of the acquisition date. Since the acquisition date, the Company has recorded adjustments to provisional amounts totaling $0.3 million. These adjustments did not have a material impact on the Company’s previously reported consolidated financial statements, and therefore the Company has not retrospectively adjusted those financial statements.
The table below summarizes the allocation of the $867.8 million adjusted purchase price, based on the acquisition date fair value of the assets acquired and the liabilities assumed as of September 30, 2017: |
| | | |
| (in thousands) | Silverback Acquisition |
| Purchase price | $ | 867,772 |
|
| Allocation of purchase price: | |
| Unproved properties | 753,763 |
|
| Proved properties | 116,700 |
|
| Other property and equipment | 56 |
|
| Liabilities | (2,747 | ) |
| Total | $ | 867,772 |
|
CENTENNIAL RESOURCE DEVELOPMENT, INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
The pro forma effects of the Silverback Acquisition were insignificant to the Company’s 2016 results of operations.
Note 3—Accounts Receivable, Accounts Payable and Accrued Expenses
Accounts receivable are comprised of the following:
| | | (in thousands) | September 30, 2017 | | December 31, 2016 | (in thousands) | March 31, 2022 | | December 31, 2021 |
| Accrued oil and gas sales receivable | $ | 32,294 |
| | $ | 11,596 |
| |
| Joint interest billings | 16,989 |
| | 2,942 |
| |
| Hedge settlements | 126 |
| | 194 |
| |
| Accrued oil and gas sales receivable, net | | Accrued oil and gas sales receivable, net | $ | 109,689 | | | $ | 57,287 | |
| Joint interest billings, net | | Joint interest billings, net | 20,882 | | | 12,449 | |
| Other | 798 |
| | 2 |
| Other | 1,266 | | | 1,559 | |
| Accounts receivable, net | $ | 50,207 |
| | $ | 14,734 |
| Accounts receivable, net | $ | 131,837 | | | $ | 71,295 | |
Accounts payable and accrued expenses are comprised of the following:
| | | | | | | | | | | |
| (in thousands) | March 31, 2022 | | December 31, 2021 |
| Accounts payable | $ | 38,520 | | | $ | 9,736 | |
| Accrued capital expenditures | 37,305 | | | 24,377 |
| Revenues payable | 46,004 | | | 40,438 |
| Accrued employee compensation and benefits | 5,791 | | | 17,218 |
| Accrued interest | 18,628 | | | 15,259 |
| Accrued derivative settlements payable | 18,715 | | | 8,591 |
| Accrued expenses and other | 13,977 | | | 14,637 |
| Accounts payable and accrued expenses | $ | 178,940 | | | $ | 130,256 | |
|
| | | | | | | |
| (in thousands) | September 30, 2017 | | December 31, 2016 |
| Accounts payable | $ | 35,132 |
| | $ | 11,210 |
|
| Accrued capital expenditures | 71,808 |
| | 24,038 |
|
| Revenues payable | 16,534 |
| | 3,815 |
|
| Payable to Silverback | — |
| | 32,293 |
|
| Accrued underwriting fees | — |
| | 7,719 |
|
| Other | 13,021 |
| | 7,025 |
|
| Accounts payable and accrued expenses | $ | 136,495 |
| | $ | 86,100 |
|
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) | March 31, 2022 | | December 31, 2021 |
| Credit Facility due 2027 | $ | — | | | $ | 25,000 | |
| | | |
| Senior Notes | | | |
| 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 | | | 170,000 | |
| Unamortized debt issuance costs on Senior Notes | (12,719) | | | (13,279) | |
| Unamortized debt discount | (1,877) | | | (1,955) | |
| Senior Notes, net | 801,203 | | | 800,565 | |
| | | |
| Total long-term debt, net | $ | 801,203 | | | $ | 825,565 | |
Credit Agreement
On February 18, 2022, CRP, the Company’s consolidated subsidiary, has aentered into an amended and restated five-year secured credit agreementfacility (the “Credit Agreement”) with a syndicate of banks, which replaced our previous credit facility that aswas set to mature in May of September 30, 2017, had a2023. The Credit Agreement increased our elected commitments to $750 million, increased our borrowing base of $350.0 million, which has been committed by lendersto $1.15 billion and is available for borrowing. A portionextended the maturity of the revolving credit facility in an aggregate amount notCredit Agreement to exceed $15.0 million may be used to issue letters of credit for the account of CRP or other designated subsidiaries of the Company.February 2027. As of September 30, 2017,March 31, 2022, the Company had $184.1no borrowings outstanding and $744.2 million in available borrowing capacity, which was net of $165.0 million in borrowings and $0.9$5.8 million in letters of credit outstanding.outstanding, under its new facility.
CENTENNIAL RESOURCE DEVELOPMENT, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
The amount available to be borrowed under CRP's revolving credit facilitythe Credit Agreement is subjectequal to athe lesser of (i) the borrowing base, that(ii) aggregate elected commitments, which is set at $750 million, or (iii) $1.5 billion. The borrowing base is redetermined semi-annually each April 1in the spring and October 1fall by the lenders in their sole discretion. CRP's credit agreementIt also allows for two2 optional borrowing base redeterminations on January 1 and July 1.in between the scheduled redeterminations. The borrowing base depends on, among other things, the volumesquantities of CRP’s proved oil and natural gas reserves, estimated cash flows from thesethose reserves, and itsthe Company’s commodity hedge positions. The borrowing base will automatically be decreased by an amount equal to 25% of the aggregate notional amount of permitted issued senior unsecured notes unless such decrease is waived by the lenders. Upon a redetermination of the borrowing base, if actual borrowings in excess ofoutstanding exceed the revised borrowing capacity, are outstanding, CRP could be required to immediately repay a portion of its debt outstandingoutstanding. Borrowings under the Credit Agreement are guaranteed by certain of CRP’s subsidiaries and the Company.
Borrowings under the Credit Agreement may be base rate loans or Secured Overnight Financing Rate (“SOFR”) loans. Interest is payable quarterly for base rate loans and at the end of the applicable interest period for SOFR loans. SOFR loans bear interest at SOFR plus an applicable margin ranging from 225 to 325 basis points, depending on the percentage of elected commitments utilized, plus an additional 10 basis point credit agreement. In connection with the October 2017 semi-annual redetermination, on November 2, 2017, the Company entered into the fifth amendmentspread adjustment. Base rate loans bear interest at a rate per annum equal to the restated credit agreementgreatest of: (i) the agent bank’s prime rate; (ii) the federal funds effective rate plus 50 basis points; or (iii) the adjusted Term SOFR rate for a one-month interest period plus 100 basis points, plus an applicable margin, ranging from 125 to increase225 basis points, depending on the percentage of the borrowing base from $350.0 millionutilized. CRP also pays a commitment fee of 37.5 to $575.0 million.50 basis points on unused elected commitment amounts under its facility.
Interest and commitment fees are accrued based on a borrowing base utilization grid set forth inThe Credit Agreement provides for, among other things, the credit agreement and are discussed in “Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations - Liquidity and Capital Resources” later in this report. Commitment fees are accrued on the unused portionability to repurchase outstanding shares of the aggregate lenderCompany’s Class A common stock (the “Common Stock”) and junior debt, subject to certain leverage and elected commitment amountavailability conditions and subject to the requirement that such repurchases are included in interest expense in the consolidated statements of operations.funded from our free cash flow. The credit facility provides for interest only payments until October 15, 2019, when the credit agreement expires and all outstanding borrowings are due. The following table shows five succeeding fiscal years of scheduled maturities for the Company’s long-term debt as of September 30, 2017 (in thousands): |
| | | | | | | | | | | | | | |
| | 2017 | | 2018 | | 2019 | | 2020 | | 2021 |
| Long-term debt | — |
| | — |
| | 165,000 |
| | — |
| | — |
|
CRP’s credit agreementCredit Agreement contains restrictive covenants that limit itsour ability to, among other things: (i) incur additional indebtedness; (ii) make investments and loans; (iii) enter into mergers; (iv) make restricted payments; (v) repurchase or declare dividends;redeem junior debt; (vi) enter into commodity hedges
CENTENNIAL RESOURCE DEVELOPMENT, INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
exceeding a specified percentage of our expected production; (vii) enter into interest rate hedges exceeding a specified percentage of ourits outstanding indebtedness; (viii) incur liens; (ix) sell assets; and (x) engage in transactions with affiliates.
CRP’s credit agreementThe 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 an add back of unused commitments under itsthe revolving credit facility and excluding non-cash derivative assets under FASB’s ASC Topic 815, Derivatives and Hedging (“ASC 815”), and certain restricted cash) to its consolidated current liabilities (excluding the current portion of long-term debt under our credit agreementthe Credit Agreement and non-cash liabilities under ASC 815)derivative liabilities), of not less than 1.0 to 1.0; and (2)
(ii) a leverage ratio, which isas defined within the Credit Agreement as the ratio of Total Funded Debt (as defined in CRP’s credit agreement)total funded debt to consolidated EBITDAX (as defined in CRP’s credit agreement) for the rollingprior four fiscal quarter period ending on such day,quarters, of not greater than 4.03.5 to 1.0.
CRP was in compliance with the covenants and the applicable financial ratios described above as of SeptemberMarch 31, 2022.
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 $163.6 million, after deducting debt issuance costs of $6.4 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.
CENTENNIAL RESOURCE DEVELOPMENT, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
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.
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, 2022, the net liability recorded related to the Convertible Senior Notes was $164.4 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.
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.
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, $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, which were fully redeemed at par in connection with the Convertible Senior Notes issuance during the second quarter of 2021. As of March 31, 2022, the remaining aggregate principal amount of 2027 Senior Notes and 2026 Senior Notes outstanding was $356.4 million and $289.4 million, respectively.
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 Credit Agreement.
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.
If CRP experiences certain defined changes of control (and, in some cases, followed by a ratings decline), each holder of the Senior Unsecured Notes may require CRP to repurchase all or a portion of its Senior Unsecured Notes for cash at a price equal to 101% of the aggregate principal amount of such Senior Unsecured Notes, plus any accrued but unpaid interest to the date of repurchase.
The indentures governing the Senior Unsecured 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 March 31, 2022 and through the filing of this report.Quarterly Report.
Upon an Event of Default (as defined in the indentures governing the Senior Unsecured Notes), the trustee or the holders of at least 25% of the aggregate principal amount of then outstanding Senior Unsecured Notes may declare the Senior Unsecured 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 Unsecured Notes to become due and payable.
CENTENNIAL RESOURCE DEVELOPMENT, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
Note 5—4—Asset Retirement Obligations
The following table summarizes the changes in the Company’s asset retirement obligations (“ARO”) associated with its working interests in oil and gas properties for the ninethree months ended September 30, 2017 (in thousands):March 31, 2022:
|
| | | |
| Asset retirement obligations at January 1, 2017 | $ | 7,226 |
|
| Additional liabilities incurred | 1,813 |
|
| Liabilities settled | (65 | ) |
| Accretion expense | 376 |
|
| Revision to estimated cash flows | (22 | ) |
| Asset retirement obligations at September 30, 2017 | $ | 9,328 |
|
| | | | | |
| (in thousands) | |
| Asset retirement obligations, beginning of period | $ | 17,240 | |
| |
| Liabilities incurred | 237 | |
| |
| Liabilities divested and settled | — | |
| Accretion expense | 262 | |
| Revisions to estimated cash flows | (92) | |
| Asset retirement obligations, end of period | $ | 17,647 | |
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, including plug and judgments including the ultimateabandonment 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 natural 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 amortization.
Note 6—5—Stock-Based Compensation
Long Term Incentive Plan
On October 7, 2016, the stockholders of the Company approved the Centennial Resource Development, Inc. 2016 Long Term Incentive Plan (the “LTIP”). An, which authorized an aggregate of 16,500,000 shares of Class A Common Stock werefor 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 Common Stock authorized for issuance under the LTIP, and as of September 30, 2017, the Company had 11,199,857 shares of Class A Common Stock available for future grants.by 8,250,000 shares. The LTIP provides for grants of restricted stock, stock options (including incentive stock options and nonqualified stock options), restricted stock units (including performance stock units), stock appreciation rights restricted stock, dividend equivalents, restricted stock units and other stock or cash basedcash-based awards.
Stock-based compensation expense is recognized within both General and administrative expenses and Exploration expense onand other expenses in the consolidated statements of operations as shown below. Historical amounts may not be representative of future amounts as the value of future awards may vary from historical amounts. Upon adoption of ASU 2016-09 in October 2016, theoperations. The Company elected to accountaccounts for forfeitures of awards granted under these plansthe LTIP as they occur in determining compensation expense.
The following table summarizes stock-based compensation expense recognized for the periods presented: | | | | | | | | | | | | | | | |
| Three Months Ended March 31, | | |
| (in thousands) | 2022 | | 2021 | | | | |
| Equity Awards | | | | | | | |
| Restricted stock | $ | 3,439 | | | $ | 3,606 | | | | | |
| Stock option awards | 31 | | | 271 | | | | | |
| Performance stock units | 2,003 | | | 639 | | | | | |
Other stock-based compensation expense(1) | 72 | | | 69 | | | | | |
| Total stock-based compensation - equity awards | 5,545 | | | 4,585 | | | | | |
| | | | | | | |
| Liability Awards | | | | | | | |
| Restricted stock units | — | | | 3,308 | | | | | |
| Performance stock units | 13,720 | | | 7,106 | | | | | |
| Total stock-based compensation - liability awards | 13,720 | | | 10,414 | | | | | |
| | | | | | | |
| Total stock-based compensation expense | $ | 19,265 | | | $ | 14,999 | | | | | |
(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.
|
| | | | | | | |
| (in thousands) | For the Three Months Ended September 30, 2017 | | For the Nine Months Ended September 30, 2017 |
| Restricted stock awards | $ | 1,490 |
| | $ | 3,364 |
|
| Stock option awards | 2,104 |
| | 5,825 |
|
| Performance stock units | 231 |
| | 231 |
|
| Total stock-based compensation expense | $ | 3,825 |
| | $ | 9,420 |
|
CENTENNIAL RESOURCE DEVELOPMENT, INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
Equity Awards
The Company has restricted stock, stock options and performance stock units (“PSUs”) outstanding that were granted under the 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, Compensation-Stock Compensation (“ASC 718”).
Restricted Stock
The following table provides information about restricted stock awards outstandingactivity during the ninethree months ended September 30, 2017:March 31, 2022:
| | | | | | | Restricted Stock | | Weighted Average Fair Value |
| | Awards | | Weighted Average Grant-Date Fair Value | |
| Outstanding as of December 31, 2016 | 256,597 |
| | $ | 20.03 |
| |
| Unvested balance as of December 31, 2021 | | Unvested balance as of December 31, 2021 | 10,143,687 | | | $ | 2.85 | |
| Granted | | Granted | 20,129 | | | 6.45 | |
| Vested | — |
| | $ | — |
| Vested | (387,929) | | | 5.03 | |
| Granted | 841,443 |
| | $ | 17.21 |
| |
| Forfeited | (8,788 | ) | | $ | 18.81 |
| Forfeited | (67,438) | | | 5.51 | |
| Outstanding as of September 30, 2017 | 1,089,252 |
| | $ | 17.86 |
| |
| Unvested balance as of March 31, 2022 | | Unvested balance as of March 31, 2022 | 9,708,449 | | | 2.75 | |
The Company grants service-based restricted stock awards to executive officers and employees, which generally vest ratably over a three-year service period, and to directors, which generally vest over a one-year service period. Compensation cost for thethese service-based restricted stock awards is based uponon the grant-dateclosing market valueprice of the award. SuchCompany’s Common Stock on the grant date, and such costs are recognized ratably over the applicable vesting period. The total fair value of restricted stock that vested during the three months ended March 31, 2022 and 2021 was $2.0 million and $2.6 million, respectively. Unrecognized compensation cost related to unvested restricted shares at September 30, 2017that were unvested as of March 31, 2022 was $15.7$18.1 million, which the Company expects to recognize over a weighted average period of 2.52.0 years.
Stock Options
Stock options that have been granted under the LTIP expire ten years from the grant date and have service-based vesting schedules of three years.vest ratably over their 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 as reported by NASDAQ on the date of grant.grant date.
Compensation cost related tofor stock options is based on the grant-date fair value of the award, which is then recognized ratably over the applicable vesting period. The Company estimates the fair value using the Black-Scholes option-pricing model. Expected volatilities are based on the re-levered asset volatility implied by a setperiod of comparable companies. Expected term is based on the simplified method, and is estimated as the average of 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.
The following table summarizes the assumptions and related information used to determine the grant-date fair value of stock options awarded during the nine months ended September 30, 2017:
|
| | | |
| | Nine Months Ended September 30, 2017 |
| Weighted average grant-date fair value per share | $ | 7.15 |
|
| Expected term (in years) | 6 |
|
| Expected stock volatility | 38.1 | % |
| Dividend yield | — | % |
| Risk-free interest rate | 2.0 | % |
The following table provides information about stock option awards outstanding during the ninethree months ended September 30, 2017:March 31, 2022:
| | | | | | | | | | | | | | | | | | | | | | | |
| Options | | Weighted Average Exercise Price | | Weighted Average Remaining Term
(in years) | | Aggregate Intrinsic Value
(in thousands) |
| Outstanding as of December 31, 2021 | 2,212,798 | | | $ | 15.31 | | | | | |
| Granted | — | | | — | | | | | |
| Exercised | (2,500) | | | 0.25 | | | | | $ | 18 | |
| Forfeited | (2,500) | | | 7.58 | | | | | |
| Expired | (25,832) | | | 16.72 | | | | | |
| Outstanding as of March 31, 2022 | 2,181,966 | | | 15.32 | | | 5.10 | | $ | 496 | |
| Exercisable as of March 31, 2022 | 2,109,122 | | | 15.71 | | | 5.10 | | $ | 194 | |
| | | | | | | |
|
| | | | | | | | | | | | | |
| | Options | | Weighted Average Exercise Price | | Weighted Average Remaining Term (in years) | | Aggregate Intrinsic Value (in thousands) |
| Outstanding as of December 31, 2016 | 2,735,500 |
| | $ | 14.67 |
| | | | |
| Exercised | — |
| | $ | — |
| | | | |
| Granted | 1,550,000 |
| | $ | 17.96 |
| | | | |
| Forfeited | (268,000 | ) | | $ | 14.53 |
| | | | |
| Outstanding as of September 30, 2017 | 4,017,500 |
| | $ | 15.95 |
| | 9.2 |
| | $ | 8,450 |
|
| Exercisable as of September 30, 2017 | — |
| | $ | — |
| | — |
| | $ | — |
|
The total fair value of stock options that vested during the three months ended March 31, 2022 and 2021 was $0.2 million and $0.3 million, respectively. The intrinsic value of the stock options exercised was minimal for the three months ended March 31, 2022 and there were no stock options exercised for the three months ended March 31, 2021. As of September 30, 2017,March 31, 2022, there was $18.9$0.1 million of unrecognized compensation cost related to unvested stock options, which the Company expects to recognize on a pro ratapro-rata basis over a weighted averageweighted-average period of 2.20.7 years.
CENTENNIAL RESOURCE DEVELOPMENT, INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
Performance Stock Units
The Company grants to executive officers performance stock units (“PSU”) 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 ourthe 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. TheThese 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 unitsPSUs subject to market conditions regardless of whether it becomes probable that these conditions will be achievedmet or not, and compensation expense is not reversed if vesting does not actually occur.
During the three months ended March 31, 2022 and 2021 there was no PSU activity. As of March 31, 2022, there was $11.0 million of unrecognized compensation cost related to PSUs that were unvested, which the Company expects to recognize on a pro-rata basis over a weighted average period of 2.3 years.
Liability Awards
The Company has performance stock units that were granted under the LTIP, which are settleable in cash and are therefore classified as liability awards in accordance with ASC 718. The Company also had restricted stock units granted under the LTIP that were settleable in cash and that were classified as liability awards, but all such units were settled in their entirety during the third quarter of 2021. Compensation cost for these 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 associated with these awards are presented as liabilities within Other long-term liabilities inthe consolidated balances sheets.
Restricted Stock Units
The grant-dateCompany granted 5.5 million restricted stock units during the third quarter of 2020 to certain officers (non-NEOs) and employees that were settleable in cash upon vesting. The restricted stock units vested 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 could vest immediately, on an accelerated basis, if they meet certain market-based vesting criteria equal to the maximum return percentage for at least 20 out of any 30 consecutive trading days. Additionally, the restricted stock units included 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.
During the second quarter of 2021, the Company amended these restricted stock unit agreements to (i) allow the units to be settleable in either cash or Common Stock upon vesting at the Company’s discretion and (ii) remove the maximum and minimum return amounts if the units are settled in Common Stock. The amended terms were effective July 1, 2021, and at that time, the Company intended to settle a portion of these restricted stock units in cash. As a result, the awards continued to be classified as liabilities in accordance with ASC 718.
During the third quarter of 2021, the maximum return event (described above) occurred resulting in an immediate vesting of all the outstanding restricted stock units on September 1, 2021. The Company settled 1.8 million of the restricted stock units in cash resulting in a $6.2 million cash payment, and the remaining units were settled in Common Stock. The portion of the units that were settled in Common Stock were recognized as equity instruments on the vesting date, which resulted in $13.6 million of incremental stock compensation expense being recognized during the year ended December 31, 2021. There are no remaining restricted stock units outstanding as of March 31, 2022.
Performance Stock Units
The Company granted 5.5 million PSUs 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 decreases by a lessor percentage, than the average percentage increase or decrease, respectively, of the stock price of a peer group of companies. These 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, 2022, there was $28.3 million of unrecognized compensation cost that represents the unvested portion of the fair value of the PSUs at March 31, 2022 and will be recognized over a weighted average period of 1.3 years.
Liability Awards Fair Value
CENTENNIAL RESOURCE DEVELOPMENT, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
The fair value of the PSUs was estimated using a Monte Carlo valuation model.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 our common stock, and the Company’s Common Stock as well as the peer companies that are specified in the PSU award agreement. The risk-free interest rate is based on U.S. Treasury yield curve rates with maturities consistent with the three-yearremaining vesting or performance period.
The following table summarizes the key assumptions and related information used to determine the grant-date fair value of performance stock units awarded during the nine months ended September 30, 2017:
liability awards as of March 31, 2022: |
| | | | | | | |
| | Nine Months Ended September 30, 2017Performance stock units |
| | |
| Number of simulations | | 1,000,000 |
10,000,000 |
| Expected implied stock volatility | | 41.6 | %65.2% |
| Dividend yield | | — | % |
| Risk-free interest rate | | 1.5 | %1.8% |
The following table provides information about performance stock units outstanding during the nine months ended September 30, 2017:
|
| | | | | | |
| | Awards | | Weighted Average Grant-Date Fair Value |
| Outstanding as of December 31, 2016 | — |
| | $ | — |
|
| Vested | — |
| | $ | — |
|
| Granted | 193,391 |
| | $ | 21.53 |
|
| Forfeited | — |
| | $ | — |
|
| Outstanding as of September 30, 2017 | 193,391 |
| | $ | 21.53 |
|
As of September 30, 2017, there was $3.9 million of unrecognized compensation cost related to unvested performance stock units, which the Company expects to recognize on a pro rata basis over a weighted average period of 2.75 years.
CENTENNIAL RESOURCE DEVELOPMENT, INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
Note 7—6—Derivative Instruments
The Company is exposed to certain risks relating to its ongoing business operations and usesmay use derivative instruments to manage its exposure to commodity price risk.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 usesuse 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 flowflows 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 opportunistically usesmay use commodity derivative instruments known as fixed price swaps to realize a known price for a specific volume of production.production, basis swaps to hedge the difference between the index price and a local or future index 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 netresulting difference in the agreed upon published third-party index price (“index price”) and the swap fixed price multiplied by the contract volume. The Company also utilizes basis swaps contracts to hedge the difference between the index price and a local index price.
The following table summarizes the approximate volumes and average contract prices of swapderivative contracts the Company had in place as of September 30, 2017:March 31, 2022: | | | | | | | | | | | | | | | | | | | | | | | |
| Period | | Volume (Bbls) | | Volume
(Bbls/d) | | Wtd. Avg. Crude Price ($/Bbl)(1) |
| Crude oil swaps | April 2022 - June 2022 | | 1,092,000 | | | 12,000 | | | $65.28 |
| July 2022 - September 2022 | | 782,000 | | | 8,500 | | | 65.46 |
| October 2022 - December 2022 | | 690,000 | | | 7,500 | | | 65.63 |
| January 2023 - March 2023 | | 225,000 | | | 2,500 | | | 73.51 |
| April 2023 - June 2023 | | 227,500 | | | 2,500 | | | 73.25 |
| July 2023 - September 2023 | | 92,000 | | | 1,000 | | | 72.98 |
| October 2023 - December 2023 | | 92,000 | | | 1,000 | | | 72.98 |
CENTENNIAL RESOURCE DEVELOPMENT, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
|
| | | | | | | | |
| | Period | | Volume (Bbl) | | Weighted Average Fixed Price/Differential ($/Bbl) (1) |
| Crude oil swaps | October 2017 - December 2017 | | 170,200 |
| | $ | 50.41 |
|
| | January 2018 - December 2018 | | 36,500 |
| | $ | 55.95 |
|
| Crude oil basis swaps | October 2017 - November 2017 | | 21,350 |
| | $ | (0.20 | ) |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Period | | Volume (Bbls) | | Volume
(Bbls/d) | | Wtd. Avg. Collar Price Ranges ($/Bbl)(2) |
| Crude oil collars | | | | | | | | | |
| NYMEX WTI | April 2022 - June 2022 | | 227,500 | | | 2,500 | | | $63.20 | - | $72.41 |
| July 2022 - September 2022 | | 276,000 | | | 3,000 | | | 75.00 | - | 92.46 |
| October 2022 - December 2022 | | 276,000 | | | 3,000 | | | 75.00 | - | 92.46 |
| January 2023 - March 2023 | | 405,000 | | | 4,500 | | | 72.22 | - | 84.08 |
| April 2023 - June 2023 | | 409,500 | | | 4,500 | | | 72.22 | - | 84.08 |
| July 2023 - September 2023 | | 230,000 | | | 2,500 | | | 72.00 | - | 82.78 |
| October 2023 - December 2023 | | 230,000 | | | 2,500 | | | 72.00 | - | 82.78 |
| | | | | | | | | |
| ICE Brent | April 2022 - June 2022 | | 91,000 | | | 1,000 | | | $90.00 | - | $105.20 |
| | | | | | | | | | | | | | | | | | | | | | | |
| Period | | Volume (Bbls) | | Volume
(Bbls/d) | | Wtd. Avg. Differential ($/Bbl)(3) |
| Crude oil basis differential swaps | April 2022 - June 2022 | | 637,000 | | | 7,000 | | | $0.34 |
| July 2022 - September 2022 | | 552,000 | | | 6,000 | | | 0.29 |
| October 2022 - December 2022 | | 552,000 | | | 6,000 | | | 0.29 |
| | | | | | | | | | | | | | | | | | | | | | | |
| Period | | Volume (Bbls) | | Volume
(Bbls/d) | | Wtd. Avg. Differential ($/Bbl)(4) |
| Crude oil roll differential swaps | April 2022 - June 2022 | | 910,000 | | | 10,000 | | | $0.71 |
| July 2022 - September 2022 | | 920,000 | | | 10,000 | | | 0.71 |
| October 2022 - December 2022 | | 920,000 | | | 10,000 | | | 0.71 |
(1) These crude oil swap transactions are settled based on the NYMEX WTI index price on each trading day within the specified monthly settlement period versus the contractual swap price for the volumes stipulated.
(2) These crude oil collars are settled based on the NYMEX WTI or ICE Brent index price, as applicable, on each trading day within the specified monthly settlement period versus the contractual floor and ceiling prices for the volumes stipulated.
(3) These crude oil basis swap transactions are settled based on the difference between the arithmetic average of ARGUS MIDLAND WTI and ARGUS WTI CUSHING indices, during each applicable monthly settlement period.
(4) These crude oil roll swap transactions are settled based on the difference between the arithmetic average of NYMEX WTI calendar month prices and the physical crude oil delivery month price. | | | | | | | | | | | | | | | | | | | | | | | |
| Period | | Volume (MMBtu) | | Volume (MMBtu/d) | | Wtd. Avg. Gas Price ($/MMBtu)(1) |
| Natural gas swaps | April 2022 - June 2022 | | 2,730,000 | | | 30,000 | | | $3.24 |
| July 2022 - September 2022 | | 2,760,000 | | | 30,000 | | | 3.24 |
| October 2022 - December 2022 | | 1,540,000 | | | 16,739 | | | 3.15 |
CENTENNIAL RESOURCE DEVELOPMENT, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
| | | | | | | | | | | | | | | | | | | | | | | |
| Period | | Volume (MMBtu) | | Volume (MMBtu/d) | | Wtd. Avg. Differential ($/MMBtu)(2) |
| Natural gas basis differential swaps | April 2022 - June 2022 | | 1,820,000 | | | 20,000 | | | $(0.45) |
| July 2022 - September 2022 | | 1,840,000 | | | 20,000 | | | (0.45) |
| October 2022 - December 2022 | | 1,840,000 | | | 20,000 | | | (0.45) |
| January 2023 - March 2023 | | 1,350,000 | | | 15,000 | | | (0.85) |
| April 2023 - June 2023 | | 1,365,000 | | | 15,000 | | | (0.85) |
| July 2023 - September 2023 | | 1,380,000 | | | 15,000 | | | (0.85) |
| October 2023 - December 2023 | | 1,380,000 | | | 15,000 | | | (0.85) |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Period | | Volume (MMBtu) | | Volume
(MMBtu/d) | | Wtd. Avg. Collar Price Ranges ($/MMBtu)(3) |
| Natural gas collars | April 2022 - June 2022 | | 1,820,000 | | | 20,000 | | | $3.50 | - | $3.97 |
| July 2022 - September 2022 | | 1,840,000 | | 20,000 | | | 3.50 | - | 3.97 |
| October 2022 - December 2022 | | 2,450,000 | | 26,630 | | | 3.87 | - | 5.06 |
| January 2023 - March 2023 | | 2,700,000 | | 30,000 | | | 4.00 | - | 5.42 |
| April 2023 - June 2023 | | 1,820,000 | | 20,000 | | | 3.13 | - | 4.05 |
| July 2023 - September 2023 | | 1,840,000 | | 20,000 | | | 3.13 | - | 4.05 |
| October 2023 - December 2023 | | 1,840,000 | | 20,000 | | | 3.21 | - | 4.89 |
| January 2024 - March 2024 | | 1,820,000 | | 20,000 | | | 3.25 | - | 5.31 |
| |
(1)
| The oil swap contracts are settled based on the month’s average daily NYMEX price of West Texas Intermediate Light Sweet Crude. The oil basis swap contracts are settled based on the difference between the arithmetic average of WTI MIDLAND ARGUS and WTI ARGUS during the relevant calculation period. |
|
| | | | | | | | |
| | Period | | Volume (MMBtu) | | Weighted Average Fixed Price/Differential ($/MMBtu) (1) |
| Natural gas swaps | October 2017 - December 2017 | | 368,000 |
| | $ | 2.94 |
|
| Natural gas basis swaps | January 2018 - December 2018 | | 1,825,000 |
| | $ | (0.43 | ) |
| | January 2019 - December 2019 | | 1,825,000 |
| | $ | (0.43 | ) |
| |
(1)
| The natural gas swap contracts are settled based on the month’s average daily NYMEX price of Henry Hub Natural Gas. The natural gas basis swap contracts are settled based on the difference between Inside FERC’s West Texas WAHA price of natural gas and the NYMEX price of Natural Gas during the relevant calculation period. |
(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.
(3) These natural gas collars are settled based on the NYMEX Henry Hub price on each trading day within the specified monthly settlement period versus the contractual floor and ceiling prices for the volumes stipulated.
Derivative Instrument Reporting. The Company’s oil and natural gas derivative instruments have not been designated as hedges for accounting purposes; therefore,purposes. Therefore, all gains and losses are recognized in the Company’s condensed consolidated statements of operations. All derivative instruments are recorded at fair value in the condensed consolidated balance sheets, other than derivative instruments that meet the “normal purchase normal sale” exclusion, and any fair value gains and losses are recognized in current period earnings.
The following table presents the impact of the Company’s derivative instruments in its consolidated statements of operations for the periods presented:
| | | | | | | | | | | | | | | |
| Three Months Ended March 31, | | |
| (in thousands) | 2022 | | 2021 | | | | |
| | | | | | | |
| | | | | | | |
| Net gain (loss) on derivative instruments | $ | (129,523) | | | $ | (51,199) | | | | | |
CENTENNIAL RESOURCE DEVELOPMENT, INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
The following table presents gains and losses for derivative instruments not designated as hedges for accounting purposes for the periods presented:
|
| | | | | | | | | | | | | | | | | | |
| | Successor | | | Predecessor | | | Successor | | | Predecessor |
| (in thousands) | For the Three Months Ended September 30, 2017 | | | For the Three Months Ended September 30, 2016 | | | For the Nine Months Ended September 30, 2017 | | | For the Nine Months Ended September 30, 2016 |
| Net gain (loss) on derivative instruments | $ | (896 | ) | | | $ | 1,741 |
| | | $ | 5,392 |
| | | $ | (4,184 | ) |
Offsetting of Derivative Assets and Liabilities. The Company’s commodity derivatives are measured at fair value and are included in the accompanying condensed consolidated balance sheets as derivative assets and liabilities. The Company nets its financial derivative instrument fair value amounts executed with the same counterparty pursuant to ISDA master netting agreements, which provide for net settlement over the term of the contract and in the event of default or termination of the contract. The following tables below summarize the location and fair value amounts of alland the Company’s derivative instrumentsclassification in the consolidated balance sheets of the Company’s derivative contracts outstanding at the respective balance dates, as well as the gross recognized derivative assets, liabilities and amounts offset in the condensed consolidated balance sheets:amounts:
|
| | | | | | | | | | | | | |
| | September 30, 2017 |
| (in thousands) | Balance Sheet Classification | | Gross Asset/Liability Amounts | | Gross Amounts Offset (1) | | Net Recognized Fair Value Assets/Liabilities |
| Derivative Assets | | | | | | | |
| Derivative instruments | Current assets | | $ | 562 |
| | $ | (179 | ) | | $ | 383 |
|
| Derivative instruments | Noncurrent assets | | 246 |
| | (4 | ) | | 242 |
|
| Total derivative assets | | | $ | 808 |
| | $ | (183 | ) | | $ | 625 |
|
| Derivative Liabilities | | | | | | | |
| Derivative instruments | Current liabilities | | $ | 629 |
| | $ | (179 | ) | | $ | 450 |
|
| Derivative instruments | Noncurrent Liabilities | | $ | 4 |
| | $ | (4 | ) | | $ | — |
|
| Total derivative liabilities | | | $ | 633 |
| | $ | (183 | ) | | $ | 450 |
|
| | | | | | | | | | | | | | | | | | | | | | | |
| Balance Sheet Classification | | Gross Fair Value Asset/Liability Amounts | | Gross Amounts Offset(1) | | Net Recognized Fair Value Assets/Liabilities |
| (in thousands) | | | March 31, 2022 |
| Derivative Assets | | | | | | | |
| Commodity contracts | Prepaid and other current assets | | $ | 10,541 | | | $ | (9,388) | | | $ | 1,153 | |
| Other noncurrent assets | | 13,238 | | | (11,040) | | | 2,198 | |
| Derivative Liabilities | | | | | | | |
| Commodity contracts | Derivative instruments | | 127,077 | | | (9,388) | | | 117,689 | |
| Other noncurrent liabilities | | 18,257 | | | (11,040) | | | 7,217 | |
| | | | | | | |
| | | December 31, 2021 |
| Derivative Assets | | | | | | | |
| Commodity contracts | Prepaid and other current assets | | $ | 3,284 | | | $ | (3,284) | | | $ | — | |
| Other noncurrent assets | | 585 | | $ | (345) | | | 240 |
| Derivative Liabilities | | | | | | | |
| Commodity contracts | Derivative instruments | | $ | 38,434 | | | $ | (3,284) | | | $ | 35,150 | |
| Other noncurrent liabilities | | 345 | | | (345) | | | — | |
| |
(1)
| The Company has agreements in place with all of its counterparties that allow for the financial right of offset for derivative assets and derivative liabilities at settlement or in the event of a default under the agreements or contract termination. |
(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 if contracts are terminated. |
| | | | | | | | | | | | | |
| | December 31, 2016 |
| (in thousands) | Balance Sheet Classification | | Gross Asset/Liability Amounts | | Gross Amounts Offset (1) | | Net Recognized Fair Value Assets/Liabilities |
| Derivative Assets | | | | | | | |
| Derivative instruments | Current assets | | $ | 739 |
| | $ | (308 | ) | | $ | 431 |
|
| Total derivative assets | | | $ | 739 |
| | $ | (308 | ) | | $ | 431 |
|
| Derivative Liabilities | | | | | | | |
| Derivative instruments | Current liabilities | | $ | 5,669 |
| | $ | (308 | ) | | $ | 5,361 |
|
| Derivative instruments | Noncurrent Liabilities | | 20 |
| | — |
| | 20 |
|
| Total derivative liabilities | | | $ | 5,689 |
| | $ | (308 | ) | | $ | 5,381 |
|
| |
(1)
| The Company has agreements in place with all of its counterparties that allow for the financial right of offset for derivative assets and 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 primarily lenders under CRP’s credit agreement.Credit Agreement. The Company usesenters into new hedge arrangements only credit agreementwith participants to hedge with,under its Credit Agreement, since these institutions are secured equally with the holders of any CRP bank debt, which eliminates the potential need to post
CENTENNIAL RESOURCE DEVELOPMENT, INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
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 ofunder CRP’s credit facilityCredit Agreement 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 FASB 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 is a listing of the Company’s netted asset or liability positions that have been measured at fair value and where they have been classifiedpresents, for each applicable level within the fair value hierarchy, as of September 30, 2017the Company’s net derivative assets and December 31, 2016:liabilities, including both current and noncurrent portions, measured at fair value on a recurring basis:
|
| | | | | | | | | | | |
| (in thousands) | Level 1 | | Level 2 | | Level 3 |
| Commodity derivative asset (liability) | | | | | |
| September 30, 2017 | $ | — |
| | $ | 175 |
| | $ | — |
|
| December 31, 2016 | — |
| | (4,950 | ) | | — |
|
| | | | | | | | | | | | | | | | | |
| (in thousands) | Level 1 | | Level 2 | | Level 3 |
| March 31, 2022 | | | | | |
| Total assets | $ | — | | | $ | 3,351 | | | $ | — | |
| Total liabilities | — | | | 124,906 | | | — | |
| December 31, 2021 | | | | | |
| Total assets | $ | — | | | $ | 240 | | | $ | — | |
| Total liabilities | — | | | 35,150 | | | — | |
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 judgementjudgment 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.
Nonrecurring Fair Value Measurements
The Company applies the provisions of the fair value measurements of assets acquired and liabilities assumed are measuredmeasurement 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 acquisition datefair value of these assets may be below their carrying value. 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 valuation techniqueapproach that is based on inputs that are not observable in the market and therefore represent Level 3 inputs. Significant inputs to the valuationexpected future net cash flows used for the impairment review and the related fair value measurement of acquired oil and natural gas proved properties include estimates of: (i) oil and gas reserves; (ii) future production decline rates; (iii) future operating and development costs; (iv) future commodity prices, including price differentials; (v) future cash flows; and (vi)(v) a market participant-based weighted average cost of capital rate. These inputs require significant judgments and estimates by the Company’s management at the time of the valuation. Refer to Note 2—Property Acquisitions for additional information on the fair value of assets acquired during 2016 and 2017.management.
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
CENTENNIAL RESOURCE DEVELOPMENT, INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
calculation of ARO include pluggingthe estimated future costs to plug and abandon oil and gas properties and reserve lives. Refer to Note 5—4—Asset Retirement Obligationsfor additional information on the Company’s ARO.
Other Financial Instruments
The carrying amounts of the Company’s cash, cash equivalents, accounts receivable, accounts payable, and accrued liabilities approximate their fair valuevalues because of the short-term maturities and/or liquid nature of these assets and liabilities.
The Company’s senior notes and borrowings under its Credit Agreement are accounted for at cost. The following table summarizes the carrying values, principal amounts and fair values of these instruments as of the dates indicated:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | March 31, 2022 | | December 31, 2021 |
| | Carrying Value | | Principal Amount | | Fair Value | | Carrying Value | | Principal Amount | | Fair value |
Credit Facility due 2027(1) | | $ | — | | | $ | — | | | $ | — | | | $ | 25,000 | | | $ | 25,000 | | | $ | 25,000 | |
5.375% Senior Notes due 2026(2) | | 285,874 | | | 289,448 | | | 280,765 | | | 285,666 | | | 289,448 | | | 286,554 | |
6.875% Senior Notes due 2027(2) | | 350,936 | | | 356,351 | | | 356,351 | | | 350,712 | | | 356,351 | | | 361,696 | |
3.25% Convertible Notes due 2028(2) | | 164,393 | | | 170,000 | | | 258,977 | | | 164,187 | | | 170,000 | | | 215,279 | |
(1) The carrying values of the amounts outstanding under CRP’s credit agreementCredit 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.
Note 9—8—Shareholders' Equity and Noncontrolling Interest
Shareholders’ EquityStock Repurchase Program
Class A Common Stock
On May 25, 2017,In February 2022, the Company’s stockholders approved the issuanceBoard of 26,100,000 shares of Class A Common Stock upon the conversion of 104,400 shares of Series B Preferred Stock that were held by affiliates of Riverstone, and there was no cash proceeds received by the Company in connection with this issuance. The 104,400 shares of Series B Preferred Stock were originally soldDirectors authorized a stock repurchase program to affiliates of Riverstone in a private placement, whereby the proceeds from such issuance were usedacquire up to fund a portion of the cash consideration for the December 2016 Silverback Acquisition.
On May 4, 2017, the Company entered into subscription agreements with certain investors pursuant to which such investors agreed to purchase, in the aggregate, 23,500,000 shares of Class A Common Stock at a purchase price of $14.50 per share, for gross proceeds of approximately $340.8 million. The closing under the subscription agreements occurred concurrently with the closing of the GMT Acquisition on June 8, 2017, and the proceeds were used to fund a majority of the purchase price of that acquisition.
Warrants
The Company’s Public Warrants were originally issued in connection with the IPO of Silver Run Acquisition Corporation. On March 1, 2017, the Company delivered a notice of redemption to all holders of its Public Warrants announcing its intention to redeem any Public Warrants that remained unexercised and outstanding after March 31, 2017 for $0.01 per Public Warrant. As of September 30, 2017, all$350 million of the Company’s Public Warrants have been either exercised foroutstanding Common Stock (the “Repurchase Program”), which is approved to run through April 1, 2024. The Company intends to use the Repurchase Program to reduce its shares of Class A Common Stock outstanding and plans to fund these repurchases with cash on hand and cash flows from operations. Repurchases may be made from time to time in the open-market or redeemed for $0.01 per Public Warrant. As a resultvia privately negotiated transactions at the Company’s discretion and will be subject to market conditions, applicable legal requirements, available liquidity, compliance with the Company’s debt and other agreements and other factors. The Repurchase Program does not require any specific number of all such Warrants exercised, the Company issued in aggregate 6,235,790 shares of Class A common stock to holders of Public Warrants.
As of September 30, 2017, 8,000,000 Private Placement Warrants remained outstanding. Private Placement Warrants are non-redeemable so long as they are heldbe acquired and can be modified or discontinued by the Company’s Sponsor or its permitted transferees. Each whole Private Placement Warrant is exercisable for one whole shareBoard of Class A Common StockDirectors at a price of $11.50 per share. The warrants became exercisable on March 1, 2017 and will expire five years afterany time. There were no shares purchased under the completion ofRepurchase Program during the Business Combination or earlier upon redemption or liquidation.
Noncontrolling Interest
The noncontrolling interest in CRP is represented by 19.2 million shares of Class C Common Stock that were issued to the Centennial Contributors in connection with the Business Combination, and such shares continue to be held by holders other than the Company. As of September 30, 2017, the Company’s noncontrolling interest was 6.9%, which declined from 7.6% as ofthree months ended March 31, 2017, due to the issuance of 23.5 million shares of Class A Common Stock on June 8, 2017. The Company has consolidated the financial position and results of operations of CRP and reflected that portion retained by the other holders as a noncontrolling interest. Refer to the consolidated statement of shareholders’ equity for a summary of the activity attributable to the noncontrolling interest during the period.
Note 10—Income Taxes
CRP is treated as a partnership for U.S. federal and most applicable state and local income tax purposes, and the Company consolidates the financial results of CRP. As a partnership, CRP is not subject to U.S. federal and certain state and local income taxes. Any taxable income or loss generated by CRP is passed through to and included in the taxable income or loss of its members, including the Company, on a pro rata basis. The Company is subject to U.S. federal income taxes, in addition to state and local income taxes, with respect to its allocable share of any taxable income or loss of CRP, as well as any stand-alone income or loss generated by the Company.
2022.
CENTENNIAL RESOURCE DEVELOPMENT, INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
Income tax expense 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 provision for income taxes for the three and nine months ended September 30, 2017 and 2016 differs from the amount that would be provided by applying the statutory U.S. federal income tax rate of 35% to pre-tax income primarily because of state income taxes and estimated permanent differences.
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 jurisdictions, permanent and temporary differences and the likelihood of recovering deferred tax assets generated in the current year. The accounting estimates used to compute the provision for income taxes may change as new events occur, more experience is obtained, additional information becomes known or as the tax environment changes.
Note 11—9—Earnings Per Share
Basic earnings per share (“EPS”) is calculated by dividing net income available to common shareholders by the weighted average shares of Common Stock outstanding during each period. DilutiveDiluted EPS is calculated by dividing adjusted net income available to common shareholders by the weighted average numbershares of diluted common sharesCommon 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 (prior to their expiration in 2021), all using the treasury stock method, and (ii) the Company’s Class C common stockpotential shares issuable under our Convertible Senior Notes, using the “if-converted” method, which is net of tax.
Shares of the Company’s unvested restricted stock and performance stock units are eligible to receive dividends; however, dividend rights will be forfeited if the award does not vest. Accordingly, these shares are not considered participating securities. Shares of the Company’s Class C Common Stock and warrants do not share in earnings or losses and are therefore not participating securities as well. In addition, the Company’s shares of Series B Preferred Stock were converted into shares of Class A Common Stock on May 25, 2017 as a result of shareholder vote. As such, the Company no longer has any participating securities and therefore does not utilize the two-class method.
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 stockshares outstanding for theeach period:
| | | | | | | | | | | | | | | |
| Three Months Ended March 31, | | |
| (in thousands, except per share data) | 2022 | | 2021 | | | | |
| Net income (loss) | $ | 15,802 | | | $ | (34,645) | | | | | |
| Add: Interest on Convertible Senior Notes, net of tax | 1,293 | | | — | | | | | |
| Adjusted net income (loss) | $ | 17,095 | | | $ | (34,645) | | | | | |
| | | | | | | |
| Basic weighted average shares of Common Stock outstanding | 284,851 | | | 278,935 | | | | | |
| Add: Dilutive effects of equity awards and ESPP shares | 7,755 | | | — | | | | | |
| Add: Dilutive effects of Convertible Senior Notes | 27,074 | | | — | | | | | |
| Diluted weighted average shares of Common Stock outstanding | 319,680 | | | 278,935 | | | | | |
| | | | | | | |
| Basic net earnings (loss) per share of Common Stock | $ | 0.06 | | | $ | (0.12) | | | | | |
| Diluted net earnings (loss) per share of Common Stock | $ | 0.05 | | | $ | (0.12) | | | | | |
|
| | | | | | | |
| (in thousands, except per share data) | For the Three Months Ended September 30, 2017 | | For the Nine Months Ended September 30, 2017 |
| Net income attributable to common shareholders | $ | 14,447 |
| | $ | 45,032 |
|
| Add: Income from conversion of Class C Common Stock | 1,193 |
| | 3,196 |
|
| Adjusted net income attributable to common shareholders | 15,640 |
| | 48,228 |
|
| | | | |
| Basic net earnings per share | $ | 0.06 |
| | $ | 0.20 |
|
| Diluted net earnings per share | $ | 0.06 |
| | $ | 0.19 |
|
| | | | |
| Basic weighted average shares outstanding | 223,622 |
| | 227,557 |
|
| Add: Dilutive effects of equity awards | 2,598 |
| | 4,481 |
|
| Add: Dilutive effects of conversion | 19,156 |
| | 19,156 |
|
| Diluted weighted average shares outstanding | 245,376 |
| | 251,194 |
|
For the three months ended September 30, 2017,The following table presents shares excluded from the diluted earnings per share calculation excludes 1.5 million stock options thatfor the periods presented as their impact was anti-dilutive:
| | | | | | | | | | | | | | | |
| Three Months Ended March 31, | | |
| (in thousands) | 2022 | | 2021(1) | | | | |
| Out-of-the-money stock options | 2,097 | | | 2,294 | | | | | |
| Restricted stock | — | | | 9,565 | | | | | |
| Performance stock units | 449 | | | 399 | | | | | |
| Employee Stock Purchase Plan | — | | | 41 | | | | | |
| Convertible Senior Notes | — | | | 27,074 | | | | | |
| Warrants | — | | | 8,000 | | | | | |
(1) The Company recognized a net loss during the three months ended March 31, 2021, and therefore all potentially dilutive securities were out-of-the-money, as there effect was anti-dilutive and forexcluded from the nine months ended September 30, 2017, thecalculation of diluted net earnings per share calculation excludes 1.0 million stock options that were out-of-the-money, as there effect was anti-dilutive.
share.
CENTENNIAL RESOURCE DEVELOPMENT, INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
Note 12—10—Transactions with Related Parties
Customer and Supplier Relationships
Riverstone Affiliated Companies. RiverstoneInvestment Group LLC and its affiliates including our Sponsor,(“Riverstone”) beneficially own a more than 10% of our equity interest in the Company and are therefore considered related parties. From time to time, the Company obtains services related to its drilling and completion activities from affiliates of Riverstone. In particular, theThe Company has paid the following amounts to the following affiliates of Riverstone for such services: (i) approximately $30.4 million and $70.6 million during the three and nine months ended September 30, 2017, respectively, to Liberty Oilfield Services, LLC; and (ii) approximately $1.7 million and $4.0 million during the three and nine months ended September 30, 2017, respectively, to Permian Tank and Manufacturing, Inc.
Other Affiliated Companies. Mark G. Papa, our President, Chief Executive Officer and Chairman of the Board, serves as a director and Chairman of the Board of Oil States International, Inc., an energy services company publicly traded on the New York Stock Exchange (“Oil States”). From time to time, the Company obtains services related to drilling and completion activities from Oil States. During the three and nine months ended September 30, 2017, the Company paid approximately $2.4 million and $6.4 million, respectively, to Oil States. At September 30, 2017, included in Accounts payable and accrued expenses on the consolidated balance sheets was $1.5 million due to Oil States.
NGP Affiliated Companies. Beginning December 28, 2016, NGP and entities affiliatedmarketing agreement with NGP were no longer considered related parties of the Company, and any expenses incurred on or after December 28, 2016 with NGP or its affiliates are no longer classified as related party expenses. However, expenses incurred before December 28, 2016 with NGP or its affiliates were classified as related party expenses as NGP beneficially owned more than 10% of our equity interest. Such transactions are detailed below.
In May 2016, the Company acquired undeveloped acreage in Reeves County, Texas and an interest in an uncompleted horizontal wellbore for approximately $9.8 million from Caird DB,Lucid Energy Delaware, LLC (“Lucid”), an affiliate of NGP. In addition,Riverstone. The Company believes that the Company paid approximately $3.3 million duringterms of the nine months ended September 30, 2016 (Predecessor),marketing agreement with Lucid are no less favorable to RockPile Energy Services, LLC (“Rockpile”). On July 3, 2017, Rockpile was acquired by an unrelated thirdeither party than those held with unaffiliated parties.
The following table summarizes the revenues recognized and is no longer an affiliatethe associated processing fees incurred from this marketing agreement as included in the consolidated statements of NGP.operations 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) | 2022 | | 2021 | | | | |
| Oil and gas sales | $ | 9,483 | | | $ | 1,075 | | | | | |
| Gathering, processing and transportation expenses | 2,519 | | | 1,205 | | | | | |
| | | | | | | | | | | |
| (in thousands) | March 31, 2022 | | December 31, 2021 |
Accounts receivable, net(1) | $ | 5,220 | | | $ | 5,562 | |
(1) Represents amounts due from Lucid and are presented net of unpaid processing fees as of the indicated period end date.
Note 13—11—Commitments and Contingencies
Commitments
In June 2017, the Company entered into a transportation service agreement whereby it is required to deliver 40,000 MMBtu per day for a term of one year, and this delivery commitment is tied to the Company’s natural gas production in Reeves and Ward counties, Texas.
The Company routinely enters into, extends or extendsamends operating agreements office and equipment leases, drilling and completion rig contracts, among others, in the ordinary course of business. Other thanDuring the above, therethree months ended March 31, 2022, the Company entered into a two-year purchase agreement to buy frac’ sand used in its well fracture stimulation process. Under the terms of this take-or-pay agreement, the Company is obligated to purchase a minimum volume of frac’ sand at a fixed price. The obligation is $44.6 million, which represents the minimum financial commitment pursuant to the terms of the contract as of March 31, 2022. There have been no other material, non-routine changes in commitments during the ninethree months ended September 30, 2017.March 31, 2022. Please refer to Note 13—Commitment13—Commitments and Contingencies included in Part II, Item 8.8 in our 2016the Company’s 2021 Annual Report.
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
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 zero 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 the reserve of a contingent liability to be recognized as of the date of these condensed consolidated financial statements.
CENTENNIAL RESOURCE DEVELOPMENT, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
Note 14—Subsequent Events12—Revenues
Revenue from Contracts with Customers
Credit Facility AmendmentCrude 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.
Oil and gas revenues presented within the consolidated statements of operations relate to the sale of oil, natural gas and NGLs as shown below:
In connection with | | | | | | | | | | | | | | | |
| Three Months Ended March 31, | | |
| 2022 | | 2021 | | | | |
| Operating revenues (in thousands): | | | | | | | |
| Oil sales | $ | 262,767 | | | $ | 133,726 | | | | | |
| Natural gas sales | 39,018 | | | 35,451 | | | | | |
| NGL sales | 45,492 | | | 23,214 | | | | | |
| Oil and gas sales | $ | 347,277 | | | $ | 192,391 | | | | | |
Oil sales
The Company’s crude oil sales contracts are generally structured whereby oil is delivered to the October 2017 semi-annual redetermination,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 November 2, 2017,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 gathering 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 entered intogenerally elects to take its residue gas product “in-kind” at the fifth amendmentplant tailgate. For these contracts, the Company evaluates when control is transferred and revenue should be recognized. Where the Company has concluded that control transfers at the tailgate of the processing facility, fees incurred prior to transfer of control are presented as gathering, processing and transportation expenses (“GP&T”) within the consolidated statements of operations. Any transportation and fractionation costs incurred subsequent to the point of transfer of control are reflected as a net reduction to natural gas and NGL sales revenues presented in the table above.
Performance obligations
For all commodity products, the Company records revenue in the month production is delivered to the purchaser. Settlement statements for natural gas and NGL sales may not be received for 30 to 90 days after the date production volumes are delivered and for crude oil, generally within 30 days after delivery has occurred. However, payment is unconditional once the performance obligations have been satisfied. At such time, the volumes delivered and sales prices can be reasonably estimated and amounts due from customers are accrued in Accounts receivable, net in the consolidated balance sheets. As of March 31, 2022 and December 31, 2021, such receivable balances were $109.7 million and $57.3 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 three months ended March 31, 2022 and 2021, 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
CENTENNIAL RESOURCE DEVELOPMENT, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
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—Subsequent Events
Amendment to LTIP
On April 27, 2022, the shareholders of the Company approved the amended and restated credit agreementLTIP, which, among other things, increased the number of shares of Common Stock authorized for issuance from 24,750,000 shares to increase the borrowing base from $350.0 million to $575.0 million.44,250,000 shares.
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of OperationOperations
The following discussion and analysis of our financial condition and results of operationoperations should be read in conjunction with the accompanying condensed 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, future market prices for oil, natural gas and NGLs, future production volumes, estimates of proved reserves, capital expenditures, economic and competitive conditions, inflation, regulatory changes, continued and future impacts of COVID-19 and other uncertainties, as well as those factors discussed above in “Cautionary Statement RegardingConcerning Forward-Looking Statements” and in our 2016 Annual Report under the heading “Item 1A. Risk Factors,”Factors” in our 2021 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
We areCentennial 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. Our assets are concentrated in the Delaware Basin, a sub-basin of the Permian Basin. Our capital programsprincipal business objective is to increase shareholder value by efficiently developing our oil and natural gas assets in an environmentally and socially responsible way, with an overall objective of improving our rates of return and generating sustainable free cash flow. Unless otherwise specified or the context otherwise requires, all references in these discussions to “Centennial,” “we,” “us,” or “our” are specifically focused on projects that we believe provide the greatest potential for repeatable successto Centennial Resource Development, Inc. and production growth.its consolidated subsidiary, Centennial Resource Production, LLC (“CRP”).
Market Conditions
The demand for oil and natural gas has been significantly impacted by the worldwide outbreak of COVID-19, specifically regarding the uncertainty surrounding the virus’s impact and because of various governmental actions taken to mitigate the spread of the virus. Concurrently, global oil and natural gas supplies have been disrupted by production curtailment agreements among the Organization of Petroleum Exporting Countries and other oil producing countries (“OPEC+”) and reduced drilling and completion activity from U.S. producers. Both OPEC+ output and U.S. drilling activity has increased since 2020 levels; however, these factors have only led to a gradual increase in oil and gas supply, and global supply has not returned to pre-pandemic levels. Further in the first quarter of 2022, Russia’s invasion of Ukraine and global sanctions placed on Russia in response have created additional downward pressures on the supply of oil and natural gas. Meanwhile, demand for oil and gas has risen steadily throughout 2021 and 2022 due to the availability of COVID-19 vaccinations, fewer government mandated restrictions and the global-wide transition away from coal to natural gas. As a result, global oil inventories have continued to decline due to the resulting supply and demand imbalances. These factors, among others, have aided in the recovery of global commodity prices throughout 2021 and have led to heightened commodity prices in the first quarter of 2022. Specifically, WTI spot prices for crude oil reached a high of $123.70 per barrel on March 8, 2022, from a low of negative $37.63 per barrel on April 20, 2020. Similarly, the Henry Hub index price for natural gas reached a high of $6.44 on February 3, 2022, from a low of $1.33 on September 22, 2020.
The oil and natural gas industry is cyclical, and commodity prices can be volatile. In the second half of 2014, oil prices began a rapid and significant decline as global and domestic supply began to outpace demand. During 2015 and through 2016, global and domestic oil supply continued to outpace demand resulting in further deterioration in realized oil prices. Thus far into 2017, commodity prices have been volatile, and it is likely that commodity prices, as well as commodity price differentials, will continue to fluctuatebe volatile due to fluctuations in global supply and demand, inventory supply levels, the continued effects from COVID-19 and variant strains of the virus, geopolitical events, federal and state government regulations, weather conditions, geopoliticalthe global transition to alternative energy sources, supply chain constraints and other factors.
The following table highlights the quarterly average NYMEX price trends for crude oil and natural gas since the first quarter of 2015:2020:
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | 2015 | | 2016 | | 2017 |
| | Q1 | | Q2 | | Q3 | | Q4 | | Q1 | | Q2 | | Q3 | | Q4 | | Q1 | | Q2 | | Q3 |
| Crude oil (per Bbl) | $ | 48.62 |
| | $ | 57.84 |
| | $ | 46.60 |
| | $ | 42.16 |
| | $ | 33.59 |
| | $ | 45.70 |
| | $ | 45.00 |
| | $ | 49.27 |
| | $ | 51.82 |
| | $ | 48.32 |
| | $ | 48.17 |
|
| Natural gas (per MMBtu) | $ | 2.81 |
| | $ | 2.74 |
| | $ | 2.73 |
| | $ | 2.24 |
| | $ | 1.98 |
| | $ | 2.25 |
| | $ | 2.80 |
| | $ | 3.17 |
| | $ | 3.06 |
| | $ | 3.14 |
| | $ | 2.95 |
|
Although oil and natural gas prices have begun to recover from the lows experienced during the first quarter of 2016, forecast prices for both oil and natural gas have not rebounded to 2014 levels. A sustained drop in oil, natural gas and NGL prices may not only decrease our revenues on a per unit basis but may 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. | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| 2020 | | 2021 | | 2022 | | | | |
| Q1 | | Q2 | | Q3 | | Q4 | | Q1 | | Q2 | | Q3 | | Q4 | | Q1 | | | | |
| Crude oil (per Bbl) | $ | 46.19 | | | $ | 28.00 | | | $ | 40.93 | | | $ | 42.66 | | | $ | 57.84 | | | $ | 66.06 | | | $ | 70.56 | | | $ | 77.09 | | | $ | 94.40 | | | | | |
| Natural gas (per MMBtu) | $ | 1.88 | | | $ | 1.65 | | | $ | 1.95 | | | $ | 2.47 | | | $ | 3.44 | | | $ | 2.88 | | | $ | 4.28 | | | $ | 4.74 | | | $ | 4.60 | | | | | |
Lower commodity prices in the future could(including realized price differentials) and lower futures curves for oil and gas prices can result in impairments of our proved oil and natural gas properties or undeveloped acreage and may materially and adversely affect our future business,operating cash flows, liquidity, financial condition, results of operations, operating cash flows, liquidity future business, and/or our ability to finance planned capital expenditures. Lower commodityrealized prices may also reduce the borrowing base under CRP’s credit agreement, 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. Alternatively, higherAdditionally, lower prices can affect our operations, which could impact our ability to comply with the covenants under our credit agreement and senior notes.
Due to the cyclical nature of the oil and natural gas industry, fluctuating demand for oilfield goods and services can put pressure on the pricing structure within our industry. As commodity prices rise, the cost of oilfield goods and services generally also increase, while during periods of commodity price declines, oilfield costs typically lag and do not adjust downward as fast as oil prices do. In addition, the U.S. inflation rate has been steadily increasing during 2021 and into 2022. These inflationary pressures may also result in increases to the costs of our oilfield goods, services and personnel, which would in turn cause our capital expenditures and operating costs to rise.
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, vendors, suppliers and the communities in which we operate. Our operational employees have been and are currently able to work on site, while certain non-operational employees have been working remotely part-time and then also reporting to our offices on a part-time basis. We have taken various precautionary measures with respect to our operational employees, direct contractors and employees who returned to our offices or job sites and have followed the Center of Disease Control (the “CDC”) recommended preventive measures to limit the spread of COVID-19. We have continued to update our safety protocols in alignment with CDC guidance and government mandates. We have not experienced any significant non-cash fair value losses being incurred onoperational disruptions, including disruptions from our derivatives, which could cause us to experience net losses when oil and natural gas prices rise. suppliers or service providers, as a result of the COVID-19 outbreak.
20172022 Highlights and Future Considerations
Operational Highlights
We operated a six rigtwo-rig drilling program during the first three months of 2022, which allowedenabled us to spud 22complete and bring online 18 gross operated wells and complete 13 operated wells during the third quarter. Over half of the completed wells were put on production during September, and the total completed wells during the quarter hadwith an average effective lateral length of approximately 5,8008,500 feet.
Acquisition Highlights
On June 8, 2017, we completed the GMT Acquisition, which consisted of interests in 36 producing horizontal wells plus approximately 11,850 undeveloped net acres in the core of the Northern Delaware Basin in Lea County, New Mexico for an unadjusted purchase price of $350.0 million.
Financing Highlights
On February 18, 2022, we closed on a new five-year revolving credit facility (the “Credit Agreement”), which replaced our previous credit agreement that was set to mature on May 4, 2023. The elected commitments under the new Credit Agreement increased to $750 million from $700 million under our previous facility, and the borrowing base increased to $1.15 billion from $700 million previously. The new Credit Agreement will mature in February 2027.
In connection withFebruary 2022, our Board of Directors authorized a stock repurchase program to acquire up to $350 million of our outstanding Class A common stock (“Common Stock”), which program is approved to run through April 1, 2024 (the “Repurchase Program”). We intend to use the GMT Acquisition, in June 2017, we issued and sold in a private placement 23,500,000Repurchase Program to reduce shares of our Class A Common Stock to certain institutional investors, which resulted in gross proceeds of approximately $340.8 million,outstanding and such proceeds were usedplan to fund the majoritythese share repurchases with cash on hand and cash flows from operations.
In connection with the October 2017 semi-annual redetermination, on November 2, 2017, the Company entered into the fifth amendment to the restated credit agreement to increase the borrowing base from $350.0 million to $575.0 million.
Results of Operations
On October 11, 2016, we consummated the acquisition of approximately 89% of the outstanding membership interests in CRP (the “Business Combination”). Our financial statement presentation distinguishes a “Predecessor” for CRP for periods prior to the Business Combination. We are the “Successor” for periods after the Business Combination, which includes consolidation of CRP subsequent to the Business Combination. Except as the context otherwise requires, references in the following discussion to the "Company," "we," "our" or "us" with respect to periods prior to the closing of the Business Combination are to CRP and its operations before the Business Combination.
Three Months Ended September 30, 2017 (Successor)March 31, 2022 Compared to Three Months Ended September 30, 2016 (Predecessor)March 31, 2021
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:
|
| | | | | | | | | | | | | | | |
| | Successor | | | Predecessor | | Increase/(Decrease) |
| | For the Three Months Ended September 30, 2017 | | | For the Three Months Ended September 30, 2016 | | $ | | % |
| Net revenues (in thousands): | | | | | | | | |
| Oil sales | $ | 87,286 |
| | | $ | 23,388 |
| | $ | 63,898 |
| | 273 | % |
| Natural gas sales | 12,852 |
| | | 2,629 |
| | 10,223 |
| | 389 | % |
| NGL sales | 11,473 |
| | | 1,304 |
| | 10,169 |
| | 780 | % |
| Total net revenues | $ | 111,611 |
| | | $ | 27,321 |
| | $ | 84,290 |
| | 309 | % |
| | | | | | | | | |
| Average sales prices: | | | | | | | | |
| Oil (per Bbl) | $ | 44.95 |
| | | $ | 41.69 |
| | $ | 3.26 |
| | 8 | % |
| Effect of derivative settlements on average price (per Bbl) | 0.21 |
| | | 12.36 |
| | (12.15 | ) | | (98 | )% |
| Oil net of hedging (per Bbl) | $ | 45.16 |
| | | $ | 54.05 |
| | $ | (8.89 | ) | | (16 | )% |
| | | | | | | | | |
| Average NYMEX price for oil (per Bbl) | $ | 48.17 |
| | | $ | 45.00 |
| | $ | 3.17 |
| | 7 | % |
| | | | | | | | | |
| Natural gas (per Mcf) | $ | 2.72 |
| | | $ | 2.67 |
| | $ | 0.05 |
| | 2 | % |
| Effect of derivative settlements on average price (per Mcf) | — |
| | | — |
| | — |
| | — | % |
| Natural gas net of hedging (per Mcf) | $ | 2.72 |
| | | $ | 2.67 |
| | $ | 0.05 |
| | 2 | % |
| | | | | | | | | |
| Average NYMEX price for natural gas (per Mcf) | $ | 2.95 |
| | | $ | 2.80 |
| | $ | 0.15 |
| | 5 | % |
| | | | | | | | | |
| NGL (per Bbl) | $ | 24.83 |
| | | $ | 14.02 |
| | $ | 10.81 |
| | 77 | % |
| | | | | | | | | |
| Net production: | | | | | | | | |
| Oil (MBbls) | 1,942 |
| | | 561 |
| | 1,381 |
| | 246 | % |
| Natural gas (MMcf) | 4,733 |
| | | 984 |
| | 3,749 |
| | 381 | % |
| NGL (MBbls) | 462 |
| | | 93 |
| | 369 |
| | 397 | % |
Total (MBoe) (1) | 3,192 |
| | | 818 |
| | 2,374 |
| | 290 | % |
| | | | | | | | | |
| Average daily net production volume: | | | | | | | | |
| Oil (Bbls/d) | 21,108 |
| | | 6,098 |
| | 15,010 |
| | 246 | % |
| Natural gas (Mcf/d) | 51,444 |
| | | 10,695 |
| | 40,749 |
| | 381 | % |
| NGL (Bbls/d) | 5,018 |
| | | 1,011 |
| | 4,007 |
| | 396 | % |
Total (Boe/d) (1) | 34,700 |
| | | 8,891 |
| | 25,809 |
| | 290 | % |
| | | | | | | | | | | | | | | | | | | | | | | |
| Three Months Ended March 31, | | Increase/(Decrease) |
| 2022 | | 2021 | | $ | | % |
| Net revenues (in thousands): | | | | | | | |
| Oil sales | $ | 262,767 | | | $ | 133,726 | | | $ | 129,041 | | | 96 | % |
| Natural gas sales | 39,018 | | | 35,451 | | | 3,567 | | | 10 | % |
| NGL sales | 45,492 | | | 23,214 | | | 22,278 | | | 96 | % |
| Oil and gas sales | $ | 347,277 | | | $ | 192,391 | | | $ | 154,886 | | | 81 | % |
| | | | | | | |
| Average sales prices: | | | | | | | |
| Oil (per Bbl) | $ | 89.17 | | | $ | 52.62 | | | $ | 36.55 | | | 69 | % |
| Effect of derivative settlements on average price (per Bbl) | (12.82) | | | (9.43) | | | (3.39) | | | (36) | % |
| Oil net of hedging (per Bbl) | $ | 76.35 | | | $ | 43.19 | | | $ | 33.16 | | | 77 | % |
| | | | | | | |
| Average NYMEX price for oil (per Bbl) | $ | 94.40 | | | $ | 57.84 | | | $ | 36.56 | | | 63 | % |
| Oil differential from NYMEX | (5.23) | | | (5.22) | | | (0.01) | | | — | % |
| | | | | | | |
| Natural gas (per Mcf) | $ | 3.93 | | | $ | 3.79 | | | $ | 0.14 | | | 4 | % |
| Effect of derivative settlements on average price (per Mcf) | (0.51) | | | 0.12 | | | (0.63) | | | (525) | % |
| Natural gas net of hedging (per Mcf) | $ | 3.42 | | | $ | 3.91 | | | $ | (0.49) | | | (13) | % |
| | | | | | | |
| Average NYMEX price for natural gas (per Mcf) | $ | 4.60 | | | $ | 3.44 | | | $ | 1.16 | | | 34 | % |
| Natural gas differential from NYMEX | (0.67) | | | 0.35 | | | (1.02) | | | (291) | % |
| | | | | | | |
| NGL (per Bbl) | $ | 49.37 | | | $ | 29.78 | | | $ | 19.59 | | | 66 | % |
| | | | | | | |
| Net production: | | | | | | | |
| Oil (MBbls) | 2,947 | | | 2,542 | | | 405 | | | 16 | % |
| Natural gas (MMcf) | 9,925 | | | 9,343 | | | 582 | | | 6 | % |
| NGL (MBbls) | 921 | | | 780 | | | 141 | | | 18 | % |
Total (MBoe)(1) | 5,522 | | | 4,878 | | | 644 | | | 13 | % |
| | | | | | | |
| Average daily net production: | | | | | | | |
| Oil (Bbls/d) | 32,741 | | | 28,239 | | | 4,502 | | | 16 | % |
| Natural gas (Mcf/d) | 110,280 | | | 103,806 | | | 6,474 | | | 6 | % |
| NGL (Bbls/d) | 10,238 | | | 8,662 | | | 1,576 | | | 18 | % |
Total (Boe/d)(1) | 61,359 | | | 54,202 | | | 7,157 | | | 13 | % |
| |
(1)
| Calculated by converting natural gas to oil equivalent barrels at a ratio of six Mcf of natural gas to one Bbl of oil. |
(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. Our totalTotal net revenues for the three months ended September 30, 2017 (Successor)March 31, 2022 were $84.3$154.9 million (or 309%81%) higher than total net revenues for the three months ended September 30, 2016 (Predecessor). Our revenuesMarch 31, 2021. Revenues are a function of oil, natural gas and NGL volumes sold and average commodity prices realized.
Our netAverage realized sales prices for oil, residue gas and NGLs increased in the first quarter of 2022 compared to the same 2021 period by 69%, 4% and 66%, respectively. The 69% increase in the average realized oil price was mainly the result of higher (63%) NYMEX crude prices between periods. The average realized sales price of natural gas increased 4% due to higher (34%) NYMEX gas prices between periods, partially offset by wider gas differentials ($1.02 per Mcf wider). The 66% increase in average realized NGL prices between periods was primarily attributable to higher Mont Belvieu spot prices for plant products in the first quarter of 2022 as compared to the first quarter of 2021. The market prices for oil, natural gas and NGLs have all been impacted by higher global supply constraints for oil and gas throughout 2021 and 2022 as discussed in the market conditions section above.
Net production volumes for oil, natural gas and NGLs increased 246%16%, 381%6% and 397%18%, respectively, between periods. The oil production volume increase between periods resulted primarily from our successful drilling successprogram in the Delaware Basin, as well as the producing properties we acquired in the Silverback and GMT Acquisitions, which collectively added 232 MBbls of net oil production to our third quarter 2017 results.Basin. Since the thirdfirst quarter of 2016,2021, we placed 49 operated wells on production, in the Delaware Basin, which added 1,4161,348 MBbls of net oil production to the thirdthree months ended March 31, 2022 as compared to 20 wells brought online since the first quarter of 2017. The increase in our operated well count is attributable2020 that added 422 MBbls of net oil production to the ramp up of our drilling program starting in the fourthfirst quarter of 2016.2021. These oil volume increases were partially offset by normal field production declines across our existing wells. Our naturalNatural gas and NGLs are produced concurrently with our crude oil volumes, resultingwhich typically results in a high correlation between fluctuations in our oil quantities sold and our natural gas and NGL quantities sold. NaturalHowever, as the majority of our wells drilled since the first quarter of 2021 have been in New Mexico, this has resulted in fewer gas and NGL volumes were also impacted bybeing produced relative to oil volumes because our New Mexico wells have a lower gas-to-oil ratio (“GOR”) than our Texas wells do. Additionally, the acreage we acquired from Silverback, which has a higher gas/oil ratio. Duringmain processor of our raw gas in New Mexico operated in partial ethane-recovery during the thirdfirst quarter of 2017, our production was made up of 39% natural gas and NGL volumes2022, as compared to 31%operating in full ethane-rejection during the third quarter of 2016.
In addition to production-related increases2021 period, and this resulted in net revenue between periods, there were also significant increases in our average realized sales prices for oil,fewer natural gas volumes and more NGLs inbeing recovered from our wet gas stream during the third quarter of 2017 compared to the same 20162022 period. Our average price for oil before the effects of hedging increased 8%, our average price for natural gas before the effects of hedging increased 2% and our average price for NGLs increased 77% between periods. Of the 8% increase in our average realized oil price, 7% of such increase was related to higher average NYMEX crude prices between periods, and the remaining 1% was attributable to slightly narrower oil differentials in the third quarter of 2017. The 2% increase in our average realized natural gas price was similarly related to higher NYMEX prices between periods (average NYMEX gas prices being 5% higher between periods) which effect was partially offset by slightly wider gas differentials experienced in the third quarter of 2017. Of the overall 77% increase in average realized NGL prices between periods, the majority of such increase was related to higher average Mont Belvieu spot prices for plant products from the third quarter 2016 to the third quarter 2017, and the remaining increase in NGL price was attributable to the fact that in August of 2016 our gas processor began transporting our NGLs to sales points via pipeline rather than trucking them.
Operating Expenses. The following table sets forth selected operating expense data for the periods indicated:
| | | | | | | | | | | | | | | | | | | | | | | |
| Three Months Ended March 31, | | Increase/(Decrease) |
| 2022 | | 2021 | | Change | | % |
| Operating costs (in thousands): | | | | | | | |
| Lease operating expenses | $ | 28,734 | | | $ | 25,861 | | | $ | 2,873 | | | 11 | % |
| Severance and ad valorem taxes | 25,051 | | | 12,583 | | | 12,468 | | | 99 | % |
| Gathering, processing and transportation expenses | 21,891 | | | 20,625 | | | 1,266 | | | 6 | % |
| Operating cost metrics: | | | | | | | |
| Lease operating expenses (per Boe) | $ | 5.20 | | | $ | 5.30 | | | $ | (0.10) | | | (2) | % |
| Severance and ad valorem taxes (% of revenue) | 7.2 | % | | 6.5 | % | | 0.7 | % | | 10 | % |
| Gathering, processing and transportation expenses (per Boe) | $ | 3.96 | | | $ | 4.23 | | | $ | (0.27) | | | (6) | % |
|
| | | | | | | | | | | | | | | |
| | Successor | | | Predecessor |
| Increase/(Decrease) |
| | For the Three Months Ended September 30, 2017 | | | For the Three Months Ended September 30, 2016 |
| $ |
| % |
| Operating expenses (in thousands): | | | | | | | | |
| Lease operating expenses | $ | 11,373 |
| | | $ | 3,656 |
|
| $ | 7,717 |
|
| 211 | % |
| Severance and ad valorem taxes | 6,448 |
| | | 1,432 |
|
| 5,016 |
|
| 350 | % |
| Gathering, processing and transportation expenses | 9,925 |
| | | 1,787 |
|
| 8,138 |
|
| 455 | % |
| Production costs per Boe: | | | | | | | | |
| Lease operating expenses | $ | 3.56 |
| | | $ | 4.47 |
|
| $ | (0.91 | ) |
| (20 | )% |
| Severance and ad valorem taxes | 2.02 |
| | | 1.75 |
|
| 0.27 |
|
| 15 | % |
| Gathering, processing and transportation expenses | 3.11 |
| | | 2.18 |
|
| 0.93 |
| | 43 | % |
Lease Operating Expenses. Our lease Lease operating expenses (“LOE”) for the three months ended September 30, 2017 (Successor)March 31, 2022 increased $7.7$2.9 million compared to the three months ended September 30, 2016 (Predecessor).March 31, 2021. Higher LOE for the thirdfirst quarter of 20172022 was primarily related to a $6.0 million(i) higher chemical costs for treating natural gas; (ii) an increase in workover expense between periods; and (iii) higher fixed and variable costs associated with a higher well count. We added 49 gross wells through successful drilling and 57 gross wells from the Silverback and GMT Acquisitions. In addition, workover activity increased $1.7 million between periods as a result of our higher well count. We had 65count, which increased to 422 gross operated horizontal wells as of September 30, 2016 as compared to 171March 31, 2022 from 397 gross operated horizontal wells as of September 30, 2017.
Our LOE on a per Boe basis, onMarch 31, 2021. These increases were partially offset by lower electricity costs between periods due to the other hand, decreased when comparinghigh electricity charges incurred in the thirdfirst quarter of 2017 to2021 as a result of the same 2016 period. severe winter storm in the Permian Basin (“Winter Storm Uri”) in February of 2021.
LOE per Boe was $3.56$5.20 for the thirdfirst quarter of 2017,2022, which represents a decrease of $0.91$0.10 per Boe (or 20%2%) from the thirdfirst quarter of 2016.2021. This decrease in rate was mainly due to flush production from new wells we drilledprimarily driven by per Boe decreases associated with (i) lower electricity expenses between periods (discussed above); and completed over the past 12 months, which has the effect of reducing(ii) fixed and semi-variable costs, on asuch as monthly equipment rentals and water handling costs, that don’t increase at the same rate as increases in production. These per Boe basis.decreases were partially offset by increases in the operating costs described above.
Severance and Ad Valorem Taxes. Severance and ad valorem taxes for the three months ended March 31, 2022 increased $12.5 million compared to the three months ended March 31, 2021. Severance taxes are primarily based on the market value of our oil and gas production at the wellhead, andwhile ad valorem taxes are generally based on the valuationassessed taxable value of ourproved developed oil and natural gas properties and vary across the different counties in which we operate. Severance and ad valorem taxes for the three months ended September 30, 2017 (Successor)
first quarter of 2022 increased $5.0$11.5 million (or 350%) compared to the three months ended September 30, 2016 (Predecessor), which wassame 2021 period primarily due to higher oil, natural gas and NGL revenues between periods. Ad valorem taxes between periods also increased $1.0 million due to higher tax assessments on our oil and gas reserve values.
Severance and ad valorem taxes as a percentage of our revenue was 5.8%total net revenues increased to 7.2% for the three months ended September 30, 2017March 31, 2022 as compared to 5.2%6.5% for the same 2016 period. Theprior year quarter. This increase in rate forwas the three months ended September 30, 2017, however, is attributable to additional reservesresult of a larger portion of our oil and productiongas volumes being produced in Texas resulting in higher ad valorem assessments, as well as the New Mexico properties we added viaduring the GMT Acquisition which carry afirst quarter of 2022, and New Mexico levies higher severance tax rate of 8.8%.rates than Texas.
Gathering, Processing and Transportation Expenses. Gathering, processing and transportation expenses (“GP&T”) for the three months ended September 30, 2017 (Successor)March 31, 2022 increased $8.1$1.3 million as compared to the three months ended September 30, 2016 (Predecessor)March 31, 2021. This increase is mainly due to (i) higher gas plant processing costs, whose variable fee portion is based on natural gas and NGL volumes soldprices, both of which increased substantially between periods whichas discussed above, and (ii) a $3.6 million decrease in reimbursements from third parties for their usage of our available firm transport capacity. These increases were partially offset by a decrease in demand fees between periods, as the first quarter of 2021 was heavily impacted by excess demand charges during Winter Storm Uri that did not reoccur in the comparable 2022 period.
On a per Boe basis, GP&T decreased from $4.23 for the first quarter of 2021 to $3.96 for the first quarter of 2022. As discussed above, a higher portion of our 2022 total oil and gas volumes were produced from our wells in New Mexico, where our GP&T rates are lower than those incurred in Texas, and this in turn resulted in a higher amount of plant processing fees and per unit transportation and gathering costs being incurredlower total GP&T rate between periods.
On a per Boe basis, our GP&T increased 43% from $2.18 for the third quarter of 2016 to $3.11 per Boe for the third quarter of 2017. This increase in rate was mainly due to a change in our gas/oil ratio whereby a higher percentage of our total production was made up of natural gas and NGL volumes during the third quarter of 2017, and thus a higher proportion of our production during this 2017 period was subject to gas gathering and transportation charges as well as gas processing fees. On a natural gas and NGL volumes basis (i.e. excluding crude oil barrels) the Boe rate increased only 14% between periods to $7.93 from $6.95 for the third quarters of 2017 and 2016, respectively. This increase was primarily the result of a new firm transportation agreement we entered into in June 2017, which provides guaranteed pipeline capacity for the Company’s natural gas sales (refer to Note 13—Commitments and Contingencies for additional information on such agreement).
Depreciation, Depletion and Amortization. The following table summarizes our depreciation, depletion and amortization (“DD&A&A”) for the periods indicated:
| | | | | | | | | | | |
| Three Months Ended March 31, |
| (in thousands, except per Boe data) | 2022 |
| 2021 |
| Depreciation, depletion and amortization | $ | 71,009 | | | $ | 63,783 | |
| Depreciation, depletion and amortization per Boe | $ | 12.86 | | | $ | 13.08 | |
|
| | | | | | | | |
| | Successor | | | Predecessor |
| (in thousands) | For the Three Months Ended September 30, 2017 | | | For the Three Months Ended September 30, 2016 |
| Depreciation, depletion and amortization | $ | 42,387 |
| | | $ | 18,454 |
|
| Depreciation, depletion and amortization per Boe | 13.28 |
| | | 22.56 |
|
Our DD&A rate can fluctuate as a result of finding and development costs incurred, acquisitions, impairments, as well as changes in proved reserves ordeveloped and proved developedundeveloped reserves. ForDD&A per Boe was $12.86 for the three months ended September 30, 2017 (Successor), DD&A expense amounted to $42.4 million, an increase of $23.9 million over the same 2016 period (Predecessor). The primary factor contributing to higher DD&A in 2017 was the increase in overall production volumes between periods, which resulted in $53.5 million of incremental DD&A expense being incurred during the thirdfirst quarter of 2017. This increase was largely offset, however, by a $29.6 million reduction in DD&A expense that was attributable2022 compared to significantly lower DD&A rates between periods.
On a Boe basis our overall DD&A rate of $13.28 for the third quarter of 2017 was 41% lower than the rate of $22.56$13.08 for the same period in 2016. The primary factor contributing to this lower2021. This decrease in DD&A rate was substantial additionsprimarily due to net upward revisions in our proved reserves and proved developed reserves over the past 12 months, coupled with reasonable drilling and completion costs over that same time period.
Exploration Expense. The following table summarizes our exploration expenses for the periods indicated:
|
| | | | | | | | |
| | Successor | | | Predecessor |
| (in thousands) | For the Three Months Ended September 30, 2017 | | | For the Three Months Ended September 30, 2016 |
| Stock-based compensation expense | $ | 465 |
| | | $ | — |
|
| Geological and geophysical costs | 1,157 |
| | | 402 |
|
| Exploration expense | $ | 1,622 |
| | | $ | 402 |
|
Exploration expense increased $1.2 million for the three months ended September 30, 2017 (Successor) compared to the same prior year period (Predecessor). Exploration expense mainly consists of topographical studies, geographical and geophysical (“G&G”) projects, and salaries and expenses of G&G personnel and consultants. The period over period increase in exploration expense is due to (i) seven geologist positions added since the thirdfirst quarter of 2016, and (ii) equity-based compensation awards that were granted2021 mainly related to G&G personnel in 2017 and during the 2016 Successor period that were not likewise granted as of September 30, 2016.higher SEC reserve pricing between periods.
General and Administrative Expenses. The following table summarizes our general and administrative (“G&A”) expenses for the periods indicated:
| | | | Successor | | | Predecessor | | Three Months Ended March 31, |
| (in thousands) | For the Three Months Ended September 30, 2017 | | | For the Three Months Ended September 30, 2016 | (in thousands) | 2022 | | 2021 |
| Stock-based compensation expense | $ | 3,360 |
| | | $ | — |
| |
| Cash general and administrative expenses | 9,951 |
| | | 4,848 |
| Cash general and administrative expenses | $ | 11,769 | | | $ | 10,632 | |
| Stock-based compensation - equity awards | | Stock-based compensation - equity awards | 5,114 | | | 4,377 | |
| Stock-based compensation - liability awards | | Stock-based compensation - liability awards | 13,720 | | | 10,247 | |
| | General and administrative expenses | $ | 13,311 |
| | | $ | 4,848 |
| General and administrative expenses | $ | 30,603 | | | $ | 25,256 | |
G&A expenses for the three months ended September 30, 2017 (Successor) increased $8.5March 31, 2022 were $30.6 million overcompared to $25.3 million for the same 2016 period (Predecessor).three months ended March 31, 2021. Higher G&A in the first quarter of 2022 was the result of a $4.2 million increase in total stock-based compensation expense between periods. This increase was primarily related to performance stock unit grants in 2020 and 2021 that are recorded at their respective fair values each balance sheet date, and such fair values increased between periods. In addition, cash G&A increased $1.2 million period over period due to $5.9higher payroll and other personnel costs.
Impairment and Abandonment Expense. During the three months ended March 31, 2022, impairment and abandonment expense was $2.6 million in higher employeeas compared to $9.2 million during the three months ended March 31, 2021. Both periods consisted solely of amortization of leasehold expiration costs associated with individually insignificant unproved properties.
Exploration and Other Expenses. The following table summarizes our exploration and other expenses for the periods indicated:
| | | | | | | | | | | |
| Three Months Ended March 31, |
| (in thousands) | 2022 |
| 2021 |
| Geological and geophysical costs | $ | 1,703 | | | $ | 613 | |
| Stock-based compensation - equity awards | 431 | | | 208 | |
| Stock-based compensation - liability awards | — | | | 167 | |
| | | |
| Other expenses | 173 | | | 107 | |
| Exploration and other expenses | $ | 2,307 | | | $ | 1,095 | |
Exploration and other expenses were $2.3 million for the three months ended March 31, 2022 compared to $1.1 million for the three months ended March 31, 2021. Exploration and other expenses mainly consist of topographical studies, geographical and geophysical (“G&G”) projects, salaries and expenses of G&G personnel and includes other operating costs. The period over period increase was primarily related to higher G&G personnel costs between periods and $3.4 million of stock-based compensation incurred duringin the thirdfirst quarter of 2017 versus none in the same prior year period. Employee-related costs were substantially higher during the third quarter of 2017 due to the number of administrative employees (i.e. non-billable to our joint interest partners) increasing from 29 at September 30, 2016 to 94 at September 30, 2017. These increases were partially offset by a decrease in transaction costs between periods. There were $1.1 million of Silver Run acquisition costs incurred during the third quarter of 2016, while no such costs were similarly incurred during the third quarter of 2017.2022.
Other Income and Expenses.
Interest Expense. The following table summarizes our interest expensesexpense for the periods indicated: | | | | | | | | | | | |
| Three Months Ended March 31, |
| (in thousands) | 2022 | | 2021 |
| Credit facility | $ | 877 | | | $ | 3,315 | |
| 8.00% Senior Secured Notes due 2025 | — | | | 2,541 | |
| 5.375% Senior Notes due 2026 | 3,889 | | | 3,889 | |
| 6.875% Senior Notes due 2027 | 6,125 | | | 6,125 | |
| 3.25% Convertible Senior Notes due 2028 | 1,381 | | | 172 | |
| Amortization of debt issuance costs and debt discount | 1,492 | | | 1,847 | |
| Interest capitalized | (610) | | | (404) | |
| Total | $ | 13,154 | | | $ | 17,485 | |
|
| | | | | | | | |
| | Successor | | | Predecessor |
| (in thousands) | For the Three Months Ended September 30, 2017 | | | For the Three Months Ended September 30, 2016 |
| Credit facility | $ | 1,480 |
| | | $ | 990 |
|
| Term Loan | — |
| | | 993 |
|
| Interest capitalized | (465 | ) | | | — |
|
| Total | $ | 1,015 |
| | | $ | 1,983 |
|
ForInterest expense decreased $4.3 million for the three months ended September 30, 2017 (Successor), we incurred $1.5 million in interest relatedMarch 31, 2022 as compared to CRP’s credit facility of which $0.5 million was capitalized as it was utilized to fund the Company’s drilling and completion capital expenditures. For the three months ended September 30, 2016 (Predecessor), we recorded $1.0March 31, 2021 primarily due to (i) $2.5 million in interest related to CRP’s credit facilityexpense on our Senior Secured Notes due 2025 that was incurred in the first quarter of 2021 but not in the 2022 period, as these notes were redeemed in April of 2021, and $1.0(ii) $2.4 million in lower interest relatedincurred on our Credit Agreement due to CRP’s term loan, whichlower borrowings outstanding during the 2022 period. These decreases were partially offset by interest on our Convertible Senior Notes that was extinguished uponincurred in 2022 but only partially in the closing2021 period due to their issuance in March of the Business Combination. 2021.
Our weighted average debtborrowings outstanding during the third quarter of 2017 was $108.5under our Credit Agreement were $27.7 million versus $124.0$330.9 million for the third quarter of 2016.three months ended March 31, 2022 and 2021, respectively. Our Credit Agreement’s weighted average effective interest rate was 3.77% during the third quarter of 2017 compared to 2.79%2.9% and 3.5% for the third quarter of 2016.three months ended March 31, 2022 and 2021, respectively.
Net Gain (Loss) on Derivative Instruments. Net gains and losses are a function of i) fluctuations(i) changes in mark-to-market derivative fair values associated with corresponding changesfluctuations in the forward price curves for the commodities underlying commodity priceseach of our hedge contracts outstanding and ii)(ii) monthly cash settlements on any closed out hedge positions during the period.
The following table presents gains and losses on our derivative instruments for the periods indicated:
| | | | | | | | | | | |
| Three Months Ended March 31, |
| (in thousands) | 2022 | | 2021 |
| Realized cash settlement gains (losses) | $ | (42,878) | | | $ | (22,886) | |
| Non-cash mark-to-market derivative gain (loss) | (86,645) | | | (28,313) | |
| Total | $ | (129,523) | | | $ | (51,199) | |
Income Tax Expense(Expense) Benefit. During the three months ended September 30, 2017 (Successor) the Company recognized $8.2 million inThe following table summarizes our pre-tax income (loss) and income tax expense. The Company's provision(expense) benefit for the periods indicated:
| | | | | | | | | | | |
| Three Months Ended March 31, |
| (in thousands) | 2022 | | 2021 |
| Income (loss) before income taxes | $ | 22,578 | | | $ | (34,645) | |
| Income tax (expense) benefit | (6,776) | | | — | |
Our provisions for income taxes for the three months ended September 30, 2017 differedMarch 31, 2022 and 2021 differs from the amountamounts that would be provided by applying the statutory U.S. federal taxstatutory rate of 35%21% to pre-tax book income (loss) primarily because ofdue to (i) permanent differences, (ii) state income taxes, and permanent differences.(iii) any changes during the period in our deferred tax asset valuation allowance.
Nine Months Ended September 30, 2017 (Successor) Compared to Nine Months Ended September 30, 2016(Predecessor)
The following table providesFor 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 production volumes: |
| | | | | | | | | | | | | | | |
| | Successor | | | Predecessor | | Increase/(Decrease) |
| | For the Nine Months Ended September 30, 2017 | | | For the Nine Months Ended September 30, 2016 | | $ | | % |
| Net revenues (in thousands): | | | | | | | | |
| Oil sales | $ | 204,702 |
| | | $ | 56,975 |
| | $ | 147,727 |
| | 259 | % |
| Natural gas sales | 33,226 |
| | | 5,717 |
| | 27,509 |
| | 481 | % |
| NGL sales | 25,844 |
| | | 3,097 |
| | 22,747 |
| | 734 | % |
| Total net revenues | $ | 263,772 |
| | | $ | 65,789 |
| | $ | 197,983 |
| | 301 | % |
| | | | | | | | | |
| Average sales prices: | | | | | | | | |
| Oil (per Bbl) | $ | 45.76 |
| | | $ | 37.48 |
| | $ | 8.28 |
| | 22 | % |
| Effect of derivative settlements on average price (per Bbl) | 0.12 |
| | | 15.30 |
| | (15.18 | ) | | (99 | )% |
| Oil net of hedging (per Bbl) | $ | 45.88 |
| | | $ | 52.78 |
| | $ | (6.90 | ) | | (13 | )% |
| | | | | | | | | |
| Average NYMEX price for oil (per Bbl) | $ | 49.44 |
| | | 41.43 |
| | 8.01 |
| | 19 | % |
| | | | | | | | | |
| Natural gas (per Mcf) | $ | 2.78 |
| | | $ | 2.24 |
| | $ | 0.54 |
| | 24 | % |
| Effect of derivative settlements on average price (per Mcf) | (0.02 | ) | | | — |
| | (0.02 | ) | | 100 | % |
| Natural gas net of hedging (per Mcf) | $ | 2.76 |
| | | $ | 2.24 |
| | $ | 0.52 |
| | 23 | % |
| | | | | | | | | |
| Average NYMEX price for natural gas (per Mcf) | $ | 3.05 |
| | | 2.34 |
| | 0.71 |
| | 30 | % |
| | | | | | | | | |
| NGL (per Bbl) | $ | 23.67 |
| | | $ | 12.80 |
| | $ | 10.87 |
| | 85 | % |
| | | | | | | | | |
| Net production: | | | | | | | | |
| Oil (MBbls) | 4,473 |
| | | 1,520 |
| | 2,953 |
| | 194 | % |
| Natural gas (MMcf) | 11,938 |
| | | 2,551 |
| | 9,387 |
| | 368 | % |
| NGL (MBbls) | 1,092 |
| | | 242 |
| | 850 |
| | 351 | % |
Total (MBoe) (1) | 7,554 |
| | | 2,187 |
| | 5,367 |
| | 245 | % |
| | | | | | | | | |
| Average daily net production volume: | | | | | | | | |
| Oil (Bbls/d) | 16,384 |
| | | 5,547 |
| | 10,837 |
| | 195 | % |
| Natural gas (Mcf/d) | 43,729 |
| | | 9,310 |
| | 34,419 |
| | 370 | % |
| NGL (Bbls/d) | 3,999 |
| | | 883 |
| | 3,116 |
| | 353 | % |
Total (Boe/d) (1) | 27,670 |
| | | 7,982 |
| | 19,688 |
| | 247 | % |
| |
(1)
| Calculated by converting natural gas to oil equivalent barrels at a ratio of six Mcf of natural gas to one Bbl of oil. |
Oil, Natural Gas and NGL Sales Revenues. Our total net revenues for the nine months of 2017 (Successor) were $198.0 million (or 301%) higher than total net revenues for the nine months of 2016 (Predecessor). Our revenues are a function of oil, natural gas and NGL volumes sold and average commodity prices realized.
Our net production volumes for oil, natural gas, and NGLs increased 194%, 368% and 351%, respectively, between periods. The oil volume increase between periods resulted primarily from our drilling success in the Delaware Basin, as well as the producing properties we acquired in the Silverback and GMT Acquisitions, which collectively added 603 MBbls of net oil production to our ninethree months ended September 30, 2017 results. SinceMarch 31, 2022, we generated pre-tax net income of $22.6 million and recorded income tax expense of $6.8 million. The primary factor increasing our income tax expense in excess of the third quarter of 2016, we have placed 49 operated wells on production in the Delaware Basin, which has added 2,826 MBbls of net oil production to the first nine months of 2017. The increase in our operated well count is attributable to the ramp up of our drilling program starting in the fourth quarter of 2016. These oil volume increases were partially offset by normal production declines across our existing wells. Our natural gas and NGLs are produced concurrently with our crude oil volumes, resulting in a high correlation between fluctuations in our oil quantities sold and our natural gas and NGL quantities sold. Natural gas and NGL volumes were also impacted by the acreage we acquired from Silverback, which has a higher gas/oil ratio. During the nine months ended September 30, 2017, our production was made up of 41% natural gas and NGL volumes as compared to 31% in the same 2016 period.
In addition to production-related increases in net revenue between periods, there were also significant increases in our average realized sales prices for oil, natural gas and NGLs when comparing the nine months ended September 30, 2017 to the same 2016 period. Our average price for oil before the effects of hedging increased 22%, our average price for natural gas before the effects of hedging increased 24%, and our average price for NGLs increased 85% between periods. Of the 22% increase in our average realized oil price, 19% of such increase was related to higher average NYMEX crude prices between periods, and the remaining 3% was attributable to slightly narrower oil differentials in the first nine months of 2017. The 24% increase in our average realized natural gas price was similarly related to higher NYMEX prices between periods (NYMEX natural gas prices being up 30% between periods) which effect was partially offset by wider gas differentials experienced in the nine months ended September 30, 2017. Of the overall 85% increase in average realized NGL prices between periods, the majority of such increase was related to higher average Mont Belvieu spot prices for plant products from the nine months ended September 30, 2016 to the comparable 2017 period. Additionally, NGL prices increased beginning in August 2016 as a result of lower transportation costs incurred by our gas processor due to the use of pipeline versus prior trucking alternatives.
Operating Expenses. The following table sets forth selected operating expense data for the periods indicated:
|
| | | | | | | | | | | | | | | |
| | Successor | | | Predecessor | | Increase/(Decrease) |
| | For the Nine Months Ended September 30, 2017 | | | For the Nine Months Ended September 30, 2016 | | $ | | % |
| Operating Expenses (in thousands): | | | | | | | | |
| Lease operating expenses | $ | 26,924 |
| | | $ | 10,295 |
| | $ | 16,629 |
| | 162 | % |
| Severance and ad valorem taxes | 14,358 |
| | | 3,523 |
| | 10,835 |
| | 308 | % |
| Gathering, processing and transportation expenses | 22,572 |
| | | 4,375 |
| | 18,197 |
| | 416 | % |
| Production costs per Boe: | | | | | | | | |
| Lease operating expenses | $ | 3.56 |
| | | $ | 4.71 |
| | $ | (1.15 | ) | | (24 | )% |
| Severance and ad valorem taxes | 1.90 |
| | | 1.61 |
| | 0.29 |
| | 18 | % |
| Gathering, processing and transportation expenses | 2.99 |
| | | 2.00 |
| | 0.99 |
| | 50 | % |
Lease Operating Expenses. Our LOE for the nine months ended September 30, 2017 (Successor) increased $16.6 million compared to the comparable 2016 period (Predecessor). Higher LOE for the first nine months of 2017 was primarily related to a $12.6 million increase associated with a higher well count. We added 49 gross wells through successful drilling and 57 gross wells from the Silverback and GMT Acquisitions. In addition, workover activity increased $4.0 million between periods as a result of our higher well count. We had 65 gross operated horizontal wells as of September 30, 2016 as compared to 171 gross operated horizontal wells as of September 30, 2017.
Our LOE on a per Boe basis, on the other hand, decreased when comparing the nine months ended September 30, 2017 to the same 2016 period. LOE per Boe was $3.56 for the nine months ended September 30, 2017, which represents a decrease of $1.15 per Boe (or 24%) from the nine months ended September 30, 2016. This decrease inU.S. statutory rate was mainly due to flush production from new wells we drilled and completed over the past 12 months, which has the effect of reducing fixed and semi-variable costs on a per Boe basis.
Severance and Ad Valorem Taxes. Severance taxes are primarily based on the market value of our production at the wellhead, and ad valorem taxes are generally based on the valuation of our oil and natural gas properties and vary across the different
counties in which we operate. Severance and ad valorem taxes for the nine months ended September 30, 2017 (Successor) increased $10.8 million (or 308%) compared to the nine months ended September 30, 2016 (Predecessor) which was primarily due to higher oil, natural gas and NGL revenues between periods. Severance and ad valorem taxes as a percentage of our revenue remained consistent for the nine months ended September 30, 2017 and 2016 at 5.4%.
Gathering, Processing and Transportation Expenses. Gathering, processing and transportation costs (“GP&T”) for the nine months ended September 30, 2017 (Successor) increased $18.2 million compared to the same 2016 period (Predecessor) due to higher natural gas and NGL volumes sold between periods, which in turn resulted in a higher amount of plant processing fees and per unit transportation and gathering costs being incurred between periods.
On a per Boe basis, our GP&T increased 50% from $2.00 for the nine months ended September 30, 2016 to $2.99 per Boe for the comparable 2017 period. This increase in rate was mainly attributable to thenon-recurring change in our gas/oil ratio whereby a higher percentage of our total productionstate apportionment rate that was made up of natural gas and NGL volumes duringreflected in the ninecurrent quarter.
For the three months ended September 30, 2017, and thus a higher proportion of our production during this 2017 period was subject to gas gathering and transportation charges as well as gas processing fees. On a natural gas and NGL volumes basis (i.e. excluding crude oil barrels) the Boe rate increased only 12% between periods from $6.56 to $7.32 for the nine months ended September 30, 2016 and 2017, respectively. This increase was primarily the result of a new firm transportation agreement we entered into in June 2017, which provides guaranteed pipeline capacity for the Company’s natural gas sales (refer to Note 13—Commitments and Contingencies for additional information on such agreement).
Depreciation, Depletion, and Amortization. The following table summarizes our DD&A for the periods indicated:
|
| | | | | | | | |
| | Successor | | | Predecessor |
| (in thousands) | For the Nine Months Ended September 30, 2017 | | | For the Nine Months Ended September 30, 2016 |
| Depreciation, depletion and amortization | $ | 102,847 |
| | | $ | 60,939 |
|
| Depreciation, depletion and amortization per Boe | 13.61 |
| | | 27.86 |
|
Our DD&A rate can fluctuate as a result of finding and development costs, acquisitions, impairments, as well as changes in proved reserves or proved developed reserves. For the nine months ended September 30, 2017 (Successor), DD&A expense amounted to $102.8 million, an increase of $41.9 million over the same 2016 period (Predecessor). The primary factor contributing to higher DD&A in 2017 was the increase in overall production volumes between periods, which resulted in $149.5 million of incremental DD&A expense being incurred during the first nine months of 2017. This increase was largely offset, however, by a $107.6 million reduction in DD&A expense that was attributable to significantly lower DD&A rates between periods.
On a Boe basis our overall DD&A rate of $13.61 for the nine months ended September 30, 2017 was 51% lower than the rate of $27.86 for the same period in 2016. The primary factor contributing to this lower DD&A rate was substantial additions to our proved reserves and proved developed reserves over the past 12 months, coupled with reasonable drilling and completion costs over that same time period.
Exploration Expense. The following table summarizes our exploration expenses for the periods indicated:
|
| | | | | | | | |
| | Successor | | | Predecessor |
| (in thousands) | For the Nine Months Ended September 30, 2017 | | | For the Nine Months Ended September 30, 2016 |
| Stock-based compensation expense | $ | 1,132 |
| | | $ | — |
|
| Geological and geophysical costs | 2,960 |
| | | 920 |
|
| Exploration expense | $ | 4,092 |
| | | $ | 920 |
|
Exploration increased $3.2 million for the nine months ended September 30, 2017 (Successor) compared to the same 2016 period (Predecessor). Exploration expense mainly consists of costs of topographical studies, G&G projects, and salaries and expenses of G&G personnel and consultants. The period over period increase in exploration expense is due to (i) seven geologist positions added since the third quarter of 2016, and (ii) equity-based compensation awards that were granted to G&G personnel in 2017 and during the 2016 Successor period that were not likewise granted as of September 30, 2016.
General and Administrative Expenses. The following table summarizes our G&A expenses for the periods indicated:
|
| | | | | | | | |
| | Successor | | | Predecessor |
| (in thousands) | For the Nine Months Ended September 30, 2017 | | | For the Nine Months Ended September 30, 2016 |
| Stock-based compensation expense | $ | 8,288 |
| | | $ | — |
|
| Cash general and administrative expenses | 27,729 |
| | | 9,735 |
|
| General and administrative expenses | $ | 36,017 |
| | | $ | 9,735 |
|
G&A expenses for the nine months ended September 30, 2017 (Successor) increased $26.3 million over the same 2016 period (Predecessor). This increase was primarily due to $14.7 million in higher employee salaries and related costs between periods, $8.3 million of stock-based compensation incurred during the nine months ended September 30, 2017 versus none in the same prior year period, and $2.9 million in increased professional fees. Employee-related costs were substantially higher during the nine months ended September 30, 2017 due to the number of administrative employees (i.e. non-billable to our joint interest partners) increasing from 29 at September 30, 2016 to 94 as of September 30, 2017, and professional fees were also higher due to costs associated with being a public company that were incurred during the 2017 period.
Other Income and Expenses.
Gain on Sale of Oil and Natural Gas Properties. Duringthe nine months ended September 30, 2017 (Successor), we recorded a gain on sale of oil and natural gas properties of $7.2 million primarily related to the sale of our Pecos County, Texas acreage.
Interest Expense. The following table summarizes our interest expenses for the periods indicated:
|
| | | | | | | | |
| | Successor | | | Predecessor |
| (in thousands) | For the Nine Months Ended September 30, 2017 | | | For the Nine Months Ended September 30, 2016 |
| Credit facility | $ | 2,633 |
| | | $ | 2,403 |
|
| Term Loan | — |
| | | 3,019 |
|
| Interest capitalized | (501 | ) | | | — |
|
| Total | $ | 2,132 |
| | | $ | 5,422 |
|
For the nine months ended September 30, 2017 (Successor), we incurred $2.6 million in interest related to CRP’s credit facility of which $0.5 million was capitalized as it was utilized to fund the Company’s drilling and completion capital expenditures. For the nine months ended September 30, 2016 (Predecessor), we recorded $2.4 million in interest related to CRP’s credit facility and $3.0 million on the term loan, which was extinguished upon closing of the Business Combination. Our weighted average debt outstanding for the nine months ended September 30, 2017 was $46.1 million versus $99.5 million for the same 2016 period. Our weighted average effective interest rate was 3.72% during the nine months ended September 30, 2017 compared to 2.67% for the comparable 2016 period.
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 corresponding changes in underlying commodity prices. and ii) monthly cash settlements of our hedged derivative positions. For the nine months ended September 30, 2017 (Successor), March 31, 2021, we recognized non-cash mark-to-market derivative gains of $5.1 million compared to non-cash mark-to-market losses of $20.8 million for the same 2016 period (Predecessor). Cash derivative settlements amounted to $0.3 million and $16.6 million in gains for the nine months of 2017 and 2016, respectively.
Income Tax Expense. During the nine months ended September 30, 2017 (Successor) the Company recognized $17.3 million income tax expense. The Company's provision for income taxes for the nine months ended September 30, 2017 differed from the amount that would be provided by applying the blended statutory U.S. federal, state, and local income tax rate of 36.1% to pre-tax income primarily because the Company released $5.1 million of itsa deferred tax asset valuation allowance of $12.4 million against net operating losses (“NOLs”) generated during the quarter. This change in our valuation allowance was the primary factor reducing our income tax benefit to zero for the first half quarter of 2017, such that income tax expense2021.
Liquidity and Capital Resources
Overview
Our developmentdrilling and acquisitioncompletion activities require us to make significant operating and capital expenditures. Historically, our primary sources of liquidity have been cash flows from operations, borrowings under CRP’s revolving credit facility, proceeds from offerings of debt or equity securities, or proceeds from the sale of oil and gas properties. Our future cash flows from operationsare subject to a number of variables, including oil and offerings ofnatural gas prices, which have been and will likely continue to be volatile. Lower commodity prices can negatively impact our cash flows and our ability to access debt or equity securitiesmarkets, and prior to the Business Combination, capital contributions from CRP’s Sponsors.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 ninethree months ended September 30, 2017:March 31, 2022:
| | | | | |
| (in millions) | Three Months Ended March 31, 2022 |
| Drilling, completion and facilities | $ | 111.6 | |
| Infrastructure, land and other | 3.1 | |
| |
| Total capital expenditures incurred | $ | 114.7 | |
|
| | | |
| (in millions) | Nine Months Ended September 30, 2017 |
| Drilling and completion capital expenditures | $ | 398.4 |
|
| Land and other | 40.5 |
|
| Facilities, seismic and other | 11.3 |
|
| Total capital expenditures | 450.2 |
|
We continually evaluate our capital needs and compare them to our capital resources. Our estimated capital expenditureWe operated a two-rig drilling program during the first three months of 2022 and plan to continue with two rigs for the remainder of the year. We expect our total capex budget for 2017 is $535.02022 to be between $365 million to $625.0$425 million, of which we expect$350 million to fund with$400 million is allocated to drilling, completion and facilities activity. We funded our capital expenditures for the three months ended March 31, 2022 entirely from cash flows from operations, and borrowings. The drilling and completion (“D&C”) portionwe expect to fund the remainder of our 2017 capital2022 capex budget represents a significant increase overentirely from cash flows from operations as well, given our anticipated level of oil and gas production, current commodity prices and our commodity hedge positions in place. We were free cash flow positive during the $97.7first three months of 2022 such that we were able to pay down all of our borrowings under our Credit Agreement during the period. Based upon current commodity prices combined with our low cost structure, we expect to continue to generate free cash flow during the remainder of 2022, which will allow us to fund our planned operational activities with minimal or no borrowings under our Credit Agreement. In addition, we may, from time to time, seek to retire or purchase our outstanding senior notes through cash purchases and/or exchanges for debt in open-market purchases, privately negotiated transactions or otherwise.
In February 2022, our Board of Directors authorized the Repurchase Program to acquire up to $350 million of D&C expenditures incurred during 2016. This increased capital budget is in responseour outstanding Common Stock. We intend to use the higher levelRepurchase Program to reduce our shares of anticipated future pricesCommon Stock outstanding and plan to fund these share repurchases with cash on hand and cash flows tofrom operations. Such repurchases would be generated from (i) new wells we drilledmade at terms and completed in latter 2016prices determined by us based upon prevailing market conditions, applicable legal requirements, available liquidity, compliance with our debt and plan to drillother agreements and complete in 2017, (ii) wells and locations we added from the Silverback Acquisition and GMT Acquisition and (iii) higher crude oil and natural gas prices experienced during the fourth quarter of 2016 and continuing into 2017, as well as our strong balance sheet position.other factors.
Because we are the operator of a high percentage of our acreage, we can control the amount and timing of theseour capital expenditures are largely discretionary.expenditures. We couldcan choose to defer or accelerate a portion of theseour planned capital expenditurescapex depending on a variety of factors, including but not limited to, the success of our drilling activities,to: prevailing and anticipated prices for oil and natural gas,gas; oil storage or transportation constraints; the success of our drilling activities; the availability of necessary equipment, infrastructure and capital,capital; the receipt and timing of required regulatory permits and approvals,approvals; seasonal conditions, drilling andconditions; property or land acquisition costscosts; and the level of participation by other working interest owners.
Based upon current oil and natural gas price expectations for the remainder of 2017, we believe that our cash flow from operations and borrowings will provide us with sufficient liquidity to execute our current capital program. However, future cash flows are subject to a number of variables, including the level of oil and natural gas production and prices, and significant additional capital expenditures will be required to more fully develop our properties. We cannot ensure that cash flows from operations and other needed capital will be available or other sources of needed capital on acceptable terms or at all. InFurther, our ability to access the event we make additional acquisitionspublic 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 amountvalue and performance of capital required is greater than the amount we have available for acquisitions at that time, we could be required to reduce the expected level of capital expenditures and/or seek additional sources for funding capital investments. As we pursue our future development program, we are actively assessing the correct mix of reserve base borrowings and debt offerings. If we require additional capital to fund acquisitions, we may also seek such capital through traditional reserve base borrowings, offerings of debt andor equity securities, asset sales or other means. If we are unable to obtain funds when needed or on acceptable terms, we may be required to curtail our current drilling program, which could result in a loss of acreage through lease expirations. In addition, we may not be able to complete acquisitions that may be favorable to us or finance the capital expenditures necessary to maintain our production or replace our reserves.
Working Capital Analysis
Our cash balances were $2.6 million and $134.1 million as of September 30, 2017 and December 31, 2016, respectively. Due to the amounts that we incur related to our drilling program, we may have temporary working capital deficits. However, we expect that our cash flows from operating activities and future borrowings under CRP’s credit facility or otherwise will be sufficient to fund our working capital needs. We expect that our pace of development, production volumes,prevailing commodity prices and differentials to NYMEX prices forother macroeconomic factors outside of our oil and natural gas production will be the largest variables affecting our working capital.control.
Analysis of Cash Flow Changes Between the Nine Months Ended September 30, 2017 (Successor) and September 30, 2016(Predecessor)
The following table summarizes our cash flows for the periods indicated:
| | | | | | | | | | | |
| Three Months Ended March 31, |
| (in thousands) | 2022 | | 2021 |
| Net cash provided by operating activities | $ | 160,120 | | | $ | 72,346 | |
| Net cash used in investing activities | (84,088) | | | (46,598) | |
| Net cash used in financing activities | (34,788) | | | (20,609) | |
|
| | | | | | | | |
| | Successor | | | Predecessor |
| (in thousands) | For the Nine Months Ended September 30, 2017 | | | For the Nine Months Ended September 30, 2016 |
| Net cash provided by operating activities | $ | 137,150 |
| | | $ | 51,511 |
|
| Net cash used in investing activities | (766,754 | ) | | | (100,975 | ) |
| Net cash provided by financing activities | 498,102 |
| | | 48,106 |
|
DuringFor the ninethree months ended September 30, 2017,March 31, 2022, we generated $137.2$160.1 million of cash provided byfrom operating activities, an increase of $85.6$87.8 million from the same period in 2016.2021. Cash provided by operating activities increased primarily due to higher net income as a results of increased crude oil, natural gas and NGLrealized prices for all commodities, higher production volumes, and higher realized sales prices for gas and NGLs as well as lowerdecreased cash interest paidcosts, and the timing of our supplier payments during the ninethree months ended September 30, 2017.March 31, 2022. These positiveincreasing factors were partially offset by higher lease operating expenses, GP&T, cash G&A, severance and ad valorem taxes, GP&T expenses, exploration costs,cash settlement losses on derivatives, and cash G&A expenses during the ninetiming of our receivable collections for the three months ended September 30, 2017March 31, 2022 as compared to the same period in 2016.2021 period. Refer to “Results of Operations” for more information on the impact of volumes and prices on revenues and for more information on increases and decreasesfluctuations in certain expensesour operating costs between periods.
During the ninethree months ended September 30, 2017,March 31, 2022, cash flows from operating activities cash on hand and $130.0 million of net borrowings under our credit facility were used to finance $354.5$81.2 million of drilling and development cash expenditures while $333.5and repay net borrowings of $25.0 million inunder our Credit Agreement.
During the three months ended March 31, 2021, cash flows from operating activities and net proceeds from the issuance of Class A common shares together withthe Convertible Senior Notes (defined below) were used to finance $46.2 million of drilling and development cash on hand, $35.0 million inexpenditures, repay net borrowings of $170.0 million under our credit facility and proceeds from the sale of oil and gas properties were used to finance $419.5fund $14.7 million in oilcapped call spread transactions.
Credit Agreement
On February 18, 2022, CRP entered into an amended and gas property acquisitions.
Revolvingrestated five-year secured Credit Facility
CRP has a credit agreementAgreement with a syndicate of banks, which replaced our previous credit facility that aswas set to mature in May of September 30, 2017, had a2023. The Credit Agreement increased our elected commitments to $750 million, increased our borrowing base of $350.0 million, which has been committed by lendersto $1.15 billion and is available for borrowing. A portionextended the maturity of the revolving credit facility in an aggregate amount notCredit Agreement to exceed $15.0 million may be used to issue letters of credit for the account of CRP or other designated subsidiaries of the Company.February 2027. As of September 30, 2017,March 31, 2022, the Company had $184.1no borrowings outstanding and $744.2 million in available borrowing capacity, which was net of $165.0 million in borrowings and $0.9$5.8 million in letters of credit outstanding.outstanding, under its new facility.
The amount available to be borrowed under CRP's revolving credit facility is subject to a borrowing base that is redetermined semiannually each April 1 and October 1 by the lenders in their sole discretion. CRP's credit agreement also allowsCredit Agreement provides for, two optional borrowing base redeterminations on January 1 and July 1. The borrowing base depends on, among other things, the volumesability to repurchase outstanding shares of CRP's proved oilCommon Stock and natural gas reserves, estimated cash flows from these reservesjunior debt, subject to certain leverage and its commodity hedge positions. The borrowing base will automatically be decreased by an amount equal to 25% of the aggregate notional amount of permitted issued senior unsecured notes unless such decrease is waived by the lenders. Upon a redetermination of the borrowing base, if borrowings in excess of the revised borrowing capacity are outstanding, CRP could be required to immediately repay a portion of its debt outstanding under its credit agreement. In connection with the October 2017 semi-annual redetermination, on November 2, 2017, the Company entered into the fifth amendmentelected commitment availability conditions and subject to the restated credit agreement to increase the borrowing baserequirement that such repurchases are funded from $350.0 million to $575.0 million.
Borrowings under CRP’s revolving credit facility 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) plus an applicable margin ranging from 225 to 325 basis points, 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; and (iii) the adjusted LIBOR rate for a one-month interest period plus 100 basis points, plus an applicable margin ranging from 125 to 225 basis points, depending on the percentage of the borrowing base utilized. At September 30, 2017, the weighted average interest rate on borrowings under CRP’s revolving credit facility was approximately 3.86%. CRP also pays a commitment fee on unused amounts of its revolving credit facility of 50 basis points. CRP may repay any amounts borrowed prior to the maturity date without any premium or penalty other than customary LIBOR breakage costs.our free cash flow. The credit facility provides for interest only payments until October 2019, when the credit agreement expires and all outstanding borrowings are due.
CRP’s credit agreementCredit Agreement contains restrictive covenants that limit itsour ability to, among other things: (i) incur additional indebtedness; (ii) make investments and loans; (iii) enter into mergers; (iv) make restricted payments; (v) repurchase or declare dividends;redeem junior debt; (vi) enter into commodity hedges exceeding a specified percentage of our expected production; (vii) enter into interest rate hedges exceeding a specified percentage of
our its outstanding indebtedness; (viii) incur liens; (ix) sell assets; and (x) engage in transactions with affiliates.
CRP’s credit agreementThe 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 an add back of unused commitments under itsthe revolving credit facility and excluding non-cash derivative assets under ASC 815 and certain restricted cash) to its consolidated current liabilities (excluding the current portion of long-term debt under our credit agreementthe Credit Agreement and non-cash liabilities under ASC 815)derivative liabilities), of not less than 1.0 to 1.0; and
(ii) a leverage ratio, which isas defined within the Credit Agreement as the ratio of Total Funded Debt (as defined in CRP’s credit agreement)total funded debt to consolidated EBITDAX (as defined in CRP’s credit agreement) for the rollingprior four fiscal quarter period ending on such day,quarters, of not greater than 4.03.5 to 1.0.
CRP was in compliance with the covenants and the applicable financial ratios described above as of September 30, 2017March 31, 2022 and through the filing of this report.Quarterly Report.
Off-Balance Sheet ArrangementsFor further information on the Credit Agreement, refer to Note 3—Long-Term Debt under Part I, Item I of this Quarterly Report.
AsConvertible Senior Notes
On March 19, 2021, CRP issued $150.0 million of September3.25% 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 notes. These issuances resulted in aggregate net proceeds to CRP of $163.6 million, which were used to repay borrowings outstanding under the Credit Agreement and to fund the cost of entering into capped call spread transactions of $14.7 million. Subsequently in April 2021, we redeemed at par all of our Senior Secured Notes (defined below), which was the intended use of proceeds from the Convertible Senior Notes offering.
The Convertible Senior 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 outstanding Senior Unsecured Notes as defined below.
The Convertible Senior Notes bear interest at an annual rate of 3.25% and are due on April 1, 2028 unless earlier repurchased, redeemed or converted. The Convertible Senior Notes may become convertible prior to April 1, 2028, upon the occurrence of certain events or conditions being met as disclosed in Note 3—Long-Term Debt under Part I, Item I of this Quarterly Report. CRP can settle the Convertible Senior Notes by paying or delivering cash, shares of the Common Stock, or a combination of cash and Common Stock, at CRP’s election.
In connection with the Convertible Senior Notes issuance, CRP entered into privately negotiated capped call spread
transactions (the “Capped Call Transactions”), that are expected to reduce potential dilution to our Common Stock upon a conversion and/or 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 subject to certain customary adjustments per the agreements).
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, $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 (the “Senior Secured Notes”). The Senior Secured Notes were fully redeemed at par in connection with the Convertible Senior Notes issuance during the second quarter of 2021.
The Senior Unsecured Notes are fully and unconditionally guaranteed on a senior unsecured basis by Centennial and each of CRP’s current subsidiaries that guarantee CRP’s Credit Agreement.
The indentures governing the Senior Unsecured 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 March 31, 2022 and through the filing of this Quarterly Report.
For further information on our Convertible Senior Notes and Senior Unsecured Notes, refer to Note 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 had no off-balance sheet arrangements.routinely enter into, modify or extend. Since December 31, 2021, there have not been any significant, non-routine changes in our contractual obligations other than the new frac’ sand agreements entered into as discussed in Note 11—Commitments and Contingencies under Part I, Item I of this Quarterly Report.
Critical Accounting Policies and Estimates
There have been no material changes during the ninethree months ended September 30, 2017March 31, 2022 to the methodology applied by management for critical accounting policies previously disclosed in our 2016 Annual Report.policies. 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 20162021 Annual Report for a discussion of our critical accounting policies and estimates.
New Accounting Pronouncements
Please refer to Note 1—Basis of Presentation and Summary of Significant Accounting Policies under Part I, Item 1. of this quarterly report forThere were no significant new accounting matters.standards adopted or new accounting pronouncements that would have potential effects to us as of March 31, 2022.
Item 3. Quantitative and Qualitative Disclosures About Market Risk
We 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 including the effects of adverse changes in commodity prices and interest rates 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 term “market risk” refers to the risk of loss arising from adverse changes in oil and natural gas prices and interest rates. 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 majorprimary market risk exposure is in the pricing that we receive for our oil, natural gas and NGLsNGL 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 three months of 2022, our oil and gas sales for the three months ended March 31, 2022 would have moved up or down $26.3 million for each 10% change in the future.oil prices per Bbl, $4.5 million for each 10% change in NGL prices per Bbl, and $3.9 million for each 10% change in natural gas prices per Mcf.
Due to this volatility, we have historically used, and we expectmay elect to continue to opportunisticallyselectively use, commodity derivative instruments such(such as collars, swaps collars and basis swaps,swaps) to mitigate price risk associated with a portion of our anticipated production. Our derivative instruments allow us to reduce, but not eliminate, the potential effects of the variability in cash flowflows that can emanate from operations due to fluctuations in oil and natural gas prices, and thereby provide increased certainty of cash flows for our drilling program and debt service requirements. These instruments provide only partial price protection against declines in oil and natural gas prices, and maybut alternatively they partially limit our potential gains from future increases in prices. CRP’s credit agreementOur Credit Agreement limits itsour ability to enter into commodity hedges covering greater than 80%85% of itsour reasonably anticipated projected production volume.from proved properties.
The following table below summarizes the approximate volumes and average contract pricesterms of swapthe derivative contracts the Companywe had in place as of SeptemberMarch 31, 2022 and additional contracts entered into through April 30, 2017:2022. Refer to Note 6—Derivative Instruments in Item 1 of Part I of this Quarterly Report for open derivative positions as of March 31, 2022. | | | | | | | | | | | | | | | | | | | | | | | |
| Period | | Volume (Bbls) | | Volume
(Bbls/d) | | Wtd. Avg. Crude Price ($/Bbl)(1) |
| Crude oil swaps | April 2022 - June 2022 | | 1,092,000 | | | 12,000 | | | $65.28 |
| July 2022 - September 2022 | | 782,000 | | | 8,500 | | | 65.46 |
| October 2022 - December 2022 | | 690,000 | | | 7,500 | | | 65.63 |
| January 2023 - March 2023 | | 225,000 | | | 2,500 | | | 73.51 |
| April 2023 - June 2023 | | 227,500 | | | 2,500 | | | 73.25 |
| July 2023 - September 2023 | | 92,000 | | | 1,000 | | | 72.98 |
| October 2023 - December 2023 | | 92,000 | | | 1,000 | | | 72.98 |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Period | | Volume (Bbls) | | Volume
(Bbls/d) | | Wtd. Avg. Collar Price Ranges ($/Bbl)(2) |
| Crude oil collars | | | | | | | | | |
| NYMEX WTI | April 2022 - June 2022 | | 227,500 | | | 2,500 | | | $63.20 | - | $72.41 |
| July 2022 - September 2022 | | 276,000 | | | 3,000 | | | 75.00 | - | 92.46 |
| October 2022 - December 2022 | | 276,000 | | | 3,000 | | | 75.00 | - | 92.46 |
| January 2023 - March 2023 | | 450,000 | | | 5,000 | | | 73.00 | - | 85.68 |
| April 2023 - June 2023 | | 455,000 | | | 5,000 | | | 73.00 | - | 85.68 |
| July 2023 - September 2023 | | 276,000 | | | 3,000 | | | 73.33 | - | 85.66 |
| October 2023 - December 2023 | | 276,000 | | | 3,000 | | | 73.33 | - | 85.66 |
| | | | | | | | | |
| ICE Brent | April 2022 - June 2022 | | 91,000 | | | 1,000 | | | $90.00 | - | $105.20 |
|
| | | | | | |
| Description & Production Period | Volume (Bbl) | | Weighted Average Fixed Price/Differential ($/Bbl) (1) |
| Crude Oil Swaps: | | | |
| October 2017 - December 2017 | 23,000 |
| | $ | 64.05 |
|
| October 2017 - December 2017 | 9,200 |
| | 54.65 |
|
| October 2017 - December 2017 | 9,200 |
| | 43.50 |
|
| October 2017 - December 2017 | 9,200 |
| | 44.85 |
|
| October 2017 - December 2017 | 9,200 |
| | 45.10 |
|
| October 2017 - December 2017 | 27,600 |
| | 44.80 |
|
| October 2017 - December 2017 | 9,200 |
| | 47.27 |
|
| October 2017 - December 2017 | 9,200 |
| | 49.00 |
|
| October 2017 - December 2017 | 46,000 |
| | 49.80 |
|
| October 2017 - December 2017 | 18,400 |
| | 52.35 |
|
| January 2018 - December 2018 | 36,500 |
| | 55.95 |
|
| Crude Oil Basis Swaps: | | | |
| October 2017 - November 2017 | 15,250 |
| | $ | (0.20 | ) |
| October 2017 - November 2017 | 6,100 |
| | (0.20 | ) |
| | | | | | | | | | | | | | | | | | | | | | | |
| Period | | Volume (Bbls) | | Volume
(Bbls/d) | | Wtd. Avg. Differential ($/Bbl)(3) |
| Crude oil differential basis swaps | April 2022 - June 2022 | | 637,000 | | | 7,000 | | | $0.34 |
| July 2022 - September 2022 | | 552,000 | | | 6,000 | | | 0.29 |
| October 2022 - December 2022 | | 552,000 | | | 6,000 | | | 0.29 |
| | | | | | | | | | | | | | | | | | | | | | | |
| Period | | Volume (Bbls) | | Volume
(Bbls/d) | | Wtd. Avg. Differential ($/Bbl)(4) |
| Crude oil roll differential swaps | April 2022 - June 2022 | | 910,000 | | | 10,000 | | | $0.71 |
| July 2022 - September 2022 | | 920,000 | | | 10,000 | | | 0.71 |
| October 2022 - December 2022 | | 920,000 | | | 10,000 | | | 0.71 |
(1) These crude oil swap transactions are settled based on the NYMEX WTI index price on each trading day within the specified monthly settlement period versus the contractual swap price for the volumes stipulated.
(2) These crude oil collars are settled based on the NYMEX WTI or ICE Brent index price, as applicable, on each trading day within the specified monthly settlement period versus the contractual floor and ceiling prices for the volumes stipulated.
(3) These crude oil basis swap transactions are settled based on the difference between the arithmetic average of ARGUS MIDLAND WTI and ARGUS WTI CUSHING indices, during each applicable monthly settlement period.
(4) These crude oil roll swap transactions are settled based on the difference between the arithmetic average of NYMEX WTI calendar month prices and the physical crude oil delivery month price.
| | | | | | | | | | | | | | | | | | | | | | | |
| Period | | Volume (MMBtu) | | Volume (MMBtu/d) | | Wtd. Avg. Gas Price ($/MMBtu)(1) |
| Natural gas swaps | April 2022 - June 2022 | | 2,730,000 | | | 30,000 | | | $3.24 |
| July 2022 - September 2022 | | 2,760,000 | | | 30,000 | | | 3.24 |
| October 2022 - December 2022 | | 1,540,000 | | | 16,739 | | | 3.15 |
| | | | | | | | | | | | | | | | | | | | | | | |
| Period | | Volume (MMBtu) | | Volume (MMBtu/d) | | Wtd. Avg. Differential ($/MMBtu)(2) |
| Natural gas basis differential swaps | April 2022 - June 2022 | | 1,820,000 | | | 20,000 | | | $(0.45) |
| July 2022 - September 2022 | | 1,840,000 | | | 20,000 | | | (0.45) |
| October 2022 - December 2022 | | 1,840,000 | | | 20,000 | | | (0.45) |
| January 2023 - March 2023 | | 2,250,000 | | | 25,000 | | | (1.11) |
| April 2023 - June 2023 | | 2,275,000 | | | 25,000 | | | (1.11) |
| July 2023 - September 2023 | | 2,300,000 | | | 25,000 | | | (1.11) |
| October 2023 - December 2023 | | 2,300,000 | | | 25,000 | | | (1.11) |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Period | | Volume (MMBtu) | | Volume (MMBtu/d) | | Wtd. Avg. Collar Price Ranges ($/MMBtu)(3) |
| Natural gas collars | April 2022 - June 2022 | | 1,820,000 | | | 20,000 | | | $3.50 | - | $3.97 |
| July 2022 - September 2022 | | 1,840,000 | | 20,000 | | | 3.50 | - | 3.97 |
| October 2022 - December 2022 | | 2,450,000 | | 26,630 | | | 3.87 | - | 5.06 |
| January 2023 - March 2023 | | 4,500,000 | | 50,000 | | | 4.00 | - | 7.12 |
| April 2023 - June 2023 | | 3,640,000 | | 40,000 | | | 3.56 | - | 6.86 |
| July 2023 - September 2023 | | 3,680,000 | | 40,000 | | | 3.56 | - | 6.86 |
| October 2023 - December 2023 | | 3,680,000 | | 40,000 | | | 3.60 | - | 7.28 |
| January 2024 - March 2024 | | 1,820,000 | | 20,000 | | | 3.25 | - | 5.31 |
| |
(1)
| The oil swap contracts are settled based on the month’s average daily NYMEX price of West Texas Intermediate Light Sweet Crude. The oil basis swap contracts are settled based on the difference between the arithmetic average of WTI MIDLAND ARGUS and WTI ARGUS during the relevant calculation period. |
|
| | | | | | |
| Description & Production Period | Volume (MMBtu) | | Weighted Average Fixed Price/Differential ($/MMBtu) (1) |
| Natural Gas Swaps: | | | |
| October 2017 - December 2017 | 368,000 |
| | $ | 2.94 |
|
| Natural Gas Basis Swaps: | | | |
| January 2018 - December 2018 | 1,825,000 |
| | $ | (0.43 | ) |
| January 2019 - December 2019 | 1,825,000 |
| | $ | (0.43 | ) |
(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.
(3) These natural gas collars are settled based on the NYMEX Henry Hub price on each trading day within the specified monthly settlement period versus the contractual floor and ceiling prices for the volumes stipulated.
Changes in the fair value of derivative contracts from December 31, 2021 to March 31, 2022, are presented below:
| | | | | |
| (in thousands) | | Commodity derivative asset (liability) |
| Net fair value of oil and gas derivative contracts outstanding as of December 31, 2021 | | $ | (34,910) | |
| Commodity hedge contract settlement payments, net of any receipts | | 42,878 | |
Cash and non-cash mark-to-market losses on commodity hedge contracts(1) | The natural | (129,523) | |
Net fair value of oil and gas swapderivative contracts are settled based on the month’s average daily NYMEX priceoutstanding as of Henry Hub Natural Gas. The natural gas basis swap contracts are settled based on the difference between Inside FERC’s West Texas WAHA price of natural gas and the NYMEX price of Natural Gas during the relevant calculation period.March 31, 2022 | | $ | (121,555) | |
The fair value of these commodity(1) At inception, new derivative instruments at September 30, 2017 was a net asset of $0.2 million. 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 September 30, 2017March 31, 2022 would cause a $1.1$45.8 million increase or $45.3 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 September 30, 2017March 31, 2022 would cause a $0.1$8.4 million increase or $8.2 million decrease, respectively, in this same fair value liability.position.
Interest Rate Risk
At September 30, 2017, we had $165.0 million of debt outstanding, with a weighted averageOur 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. CRP’s Credit Agreement interest rate of 3.86%. Interest is calculated under the terms of CRP’s credit agreement based on a LIBOR spread. Assuming no change in the amount outstanding, the impact on interest expense of a 1.0% increase or decrease in the assumed weighted averageSOFR spread, which exposes us to interest rate would be approximately $1.7 million per year.risk to the extent we have borrowings outstanding under this credit facility. As of March 31, 2022, we had no borrowings outstanding under the Credit Agreement. 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 $801.2 million consists of our senior notes, which have fixed interest rates; therefore, this balance is not affected by interest rate movements. For additional information regarding our debt instruments, see Note 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 our 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 September 30, 2017.March 31, 2022. Our disclosure controls and procedures are designed to provide reasonable assurance that the information required to be disclosed by us 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 September 30, 2017March 31, 2022 at the reasonable assurance level.
Changes in Internal Control over Financial Reporting
There have not been anywere no changes in ourthe system of internal control over financial reporting that occurred(as defined in Rule 13a-15(f) and Rule 15d-15(f) under the Exchange Act) during the three months ended September 30, 2017March 31, 2022 that have materially affected, or are reasonably likely to materially affect, ourthe Company’s internal controlscontrol over financial reporting.
PART II. OTHER INFORMATION
Item 1. Legal Proceedings.Proceedings
From timeRefer to time, we are party to ongoingin Item 1, Note 11—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 do not believe the results of these proceedings, individually or in the aggregate, will have a material adverse effect on our business, financial condition, results of operations or liquidity.proceedings.
Item 1A. Risk Factors.Factors
In addition to the other information set forth in this report,Quarterly Report, you should carefully consider the risk factors and other cautionary statements described under the heading “Item 1A. Risk Factors” included in our 20162021 Annual Report and the risk factors and other cautionary statements contained in our other SEC filings, which could materially affect our businesses, financial condition, or future results.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. There have been no material changes in our risk factors from those described in our 20162021 Annual Report or our other SEC filings.
Item 6. Exhibits.
Exhibits not incorporated by reference to a prior filing are designated by an asterisk (*) and are filed herewith; all exhibits not so designated are incorporated by reference to a prior SEC filing as indicated.
|
| | | | | | | |
Exhibit
Number | | Description of Exhibit |
| 3.1 | | Second |
| 3.2 | | |
| 3.3 | | |
| 3.4 | | |
| 3.5 | | |
| 3.6 | | |
| 10.1# | | |
| 10.2*# | | |
| 31.1* | | |
| | |
| | |
| | |
| 101.INS* | | Inline XBRL Instance Document.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* | | 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 Executive Vice President and Chief Financial Officer Treasurer and Assistant Secretary (Principal Financial Officer) |
| | |
| Date: | November 6, 2017May 5, 2022 |