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 SeptemberJune 30, 20172022
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 OctoberJuly 31, 2017,2022, there were 256,731,091285,059,255 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 ability to identify, complete and effectively integrate acquisitions of properties or businesses, including our pending merger with Colgate Energy Partners III, LLC;
•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
We 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 |
|
| | | | | | | | | | | |
| June 30, 2022 | | December 31, 2021 |
| ASSETS | | | |
| Current assets | | | |
| Cash and cash equivalents | $ | 201,092 | | | $ | 9,380 | |
| Accounts receivable, net | 141,598 | | | 71,295 | |
| Prepaid and other current assets | 7,189 | | | 5,860 | |
| Total current assets | 349,879 | | | 86,535 | |
| Property and Equipment | | | |
| Oil and natural gas properties, successful efforts method | | | |
| Unproved properties | 984,264 | | | 1,040,386 |
| Proved properties | 4,929,108 | | | 4,623,726 |
| Accumulated depreciation, depletion and amortization | (2,140,982) | | | (1,989,489) |
| Total oil and natural gas properties, net | 3,772,390 | | | 3,674,623 |
| Other property and equipment, net | 13,167 | | | 11,197 |
| Total property and equipment, net | 3,785,557 | | | 3,685,820 | |
| Noncurrent assets | | | |
| Operating lease right-of-use assets | 54,934 | | | 16,385 | |
| Other noncurrent assets | 33,660 | | | 15,854 |
| TOTAL ASSETS | $ | 4,224,030 | | | $ | 3,804,594 | |
| LIABILITIES AND EQUITY | | | |
| Current liabilities | | | |
| Accounts payable and accrued expenses | $ | 208,222 | | | $ | 130,256 | |
| Operating lease liabilities | 21,124 | | | 1,413 | |
| Derivative instruments | 83,541 | | | 35,150 | |
| Other current liabilities | 3,214 | | | 1,080 | |
| Total current liabilities | 316,101 | | | 167,899 |
| Noncurrent liabilities | | | |
| Long-term debt, net | 801,849 | | | 825,565 | |
| Asset retirement obligations | 18,151 | | | 17,240 | |
| Deferred income taxes | 50,293 | | | 2,589 | |
| Operating lease liabilities | 35,724 | | | 16,002 | |
| Other noncurrent liabilities | 32,344 | | | 24,579 | |
| Total liabilities | 1,254,462 | | | 1,053,874 |
| Commitments and contingencies (Note 12) | 0 | | 0 |
| Shareholders’ equity | | | |
| Common stock, $0.0001 par value, 620,000,000 shares authorized; 297,060,327 shares issued and 284,992,650 shares outstanding at June 30, 2022 and 294,260,623 shares issued and 284,696,972 shares outstanding at December 31, 2021 | 30 | | | 29 | |
| Additional paid-in capital | 3,024,236 | | | 3,013,017 | |
| Retained earnings (accumulated deficit) | (54,698) | | | (262,326) | |
| Total Shareholders' equity | 2,969,568 | | | 2,750,720 | |
| TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY | $ | 4,224,030 | | | $ | 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 June 30, | | Six Months Ended June 30, |
| | Successor | | | Predecessor | | Successor | | | Predecessor | | 2022 | | 2021 | | 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 | $ | 472,654 | | | $ | 232,577 | | | $ | 819,931 | | | $ | 424,968 | |
| Operating expenses | | | | | | | | | | Operating expenses | |
| Lease operating expenses | 11,373 |
| | | 3,656 |
| | 26,924 |
| | | 10,295 |
| Lease operating expenses | 28,900 | | | 22,976 | | | 57,634 | | | 48,837 | |
| Severance and ad valorem taxes | 6,448 |
| | | 1,432 |
| | 14,358 |
| | | 3,523 |
| Severance and ad valorem taxes | 34,695 | | | 15,784 | | | 59,746 | | | 28,367 | |
| Gathering, processing and transportation expenses | 9,925 |
| | | 1,787 |
| | 22,572 |
| | | 4,375 |
| Gathering, processing and transportation expenses | 25,756 | | | 19,494 | | | 47,647 | | | 40,119 | |
| Depreciation, depletion and amortization | 42,387 |
| | | 18,454 |
| | 102,847 |
| | | 60,939 |
| Depreciation, depletion and amortization | 82,117 | | | 73,429 | | | 153,126 | | | 137,212 | |
| 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 | 9,947 | | | 28,807 | | | 40,550 | | | 54,063 | |
| Merger and integration expense | | Merger and integration expense | 5,685 | | | — | | | 5,685 | | | — | |
| Impairment and abandonment expense | | Impairment and abandonment expense | 506 | | | 9,199 | | | 3,133 | | | 18,399 | |
| Exploration and other expenses | | Exploration and other expenses | 1,954 | | | 1,764 | | | 4,261 | | | 2,859 | |
| Total operating expenses | 85,066 |
| | | 32,228 |
| | 206,781 |
| | | 92,333 |
| Total operating expenses | 189,560 | | | 171,453 | | | 371,782 | | | 329,856 | |
| 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 | (1,406) | | | (8) | | | (1,324) | | | 36 | |
| Proceeds from terminated sale of assets | | Proceeds from terminated sale of assets | — | | | 5,983 | | | — | | | 5,983 | |
| Income (loss) from operations | | Income (loss) from operations | 281,688 | | | 67,099 | | | 446,825 | | | 101,131 | |
| | 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 | (14,326) | | | (15,182) | | | (27,480) | | | (32,667) | |
| Gain (loss) on extinguishment of debt | | Gain (loss) on extinguishment of debt | — | | | (22,156) | | | — | | | (22,156) | |
| Net gain (loss) on derivative instruments | (896 | ) | | | 1,741 |
| | 5,392 |
| | | (4,184 | ) | Net gain (loss) on derivative instruments | (34,134) | | | (54,959) | | | (163,657) | | | (106,158) | |
| Other income | — |
| | | — |
| | — |
| | | 6 |
| |
| Other income (expense) | (2,052 | ) | | | (227 | ) | | 10,476 |
| | | (9,589 | ) | Other income (expense) | 85 | | | 143 | | | 203 | | | 150 | |
| Total other income (expense) | | Total other income (expense) | (48,375) | | | (92,154) | | | (190,934) | | | (160,831) | |
| | Income (loss) before income taxes | 24,493 |
| | | (5,134 | ) | | 67,467 |
| | | (36,133 | ) | Income (loss) before income taxes | 233,313 | | | (25,055) | | | 255,891 | | | (59,700) | |
| Income tax (expense) benefit | (8,233 | ) | | | — |
| | (17,302 | ) | | | 406 |
| Income tax (expense) benefit | (41,487) | | | — | | | (48,263) | | | — | |
| Net income (loss) | 16,260 |
| | | (5,134 | ) | | $ | 50,165 |
| | | $ | (35,727 | ) | Net income (loss) | $ | 191,826 | | | $ | (25,055) | | | $ | 207,628 | | | $ | (59,700) | |
| 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 | $ | 0.67 | | | $ | (0.09) | | | $ | 0.73 | | | $ | (0.21) | |
| Diluted | $ | 0.06 |
| | | | | $ | 0.19 |
| | | | Diluted | $ | 0.60 | | | $ | (0.09) | | | $ | 0.66 | | | $ | (0.21) | |
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 |
|
| | | | | | | | | | | |
| Six Months Ended June 30, |
| 2022 |
| 2021 |
| Cash flows from operating activities: | | | |
| Net income (loss) | $ | 207,628 | | | $ | (59,700) | |
| Adjustments to reconcile net income (loss) to net cash provided by operating activities: | | | |
| Depreciation, depletion and amortization | 153,126 | | | 137,212 | |
| Stock-based compensation expense - equity awards | 12,202 | | | 9,066 | |
| Stock-based compensation expense - liability awards | 5,127 | | | 25,074 | |
| Impairment and abandonment expense | 3,133 | | | 18,399 | |
| Deferred tax expense (benefit) | 47,663 | | | — | |
| Net (gain) loss on sale of long-lived assets | 1,324 | | | (36) | |
| Non-cash portion of derivative (gain) loss | 47,131 | | | 45,759 | |
| Amortization of debt issuance costs and debt discount | 4,226 | | | 2,886 | |
| (Gain) loss on extinguishment of debt | — | | | 22,156 | |
| Changes in operating assets and liabilities: | | | |
| (Increase) decrease in accounts receivable | (62,751) | | | (33,483) | |
| (Increase) decrease in prepaid and other assets | (6,201) | | | (9) | |
| Increase (decrease) in accounts payable and other liabilities | 42,491 | | | 12,301 | |
| Net cash provided by operating activities | 455,099 | | | 179,625 | |
| Cash flows from investing activities: | | | |
| Acquisition of oil and natural gas properties | (2,592) | | | (638) | |
| Drilling and development capital expenditures | (224,011) | | | (126,665) | |
| Purchases of other property and equipment | (2,863) | | | (471) | |
| Proceeds from sales of oil and natural gas properties | 863 | | | 698 | |
| Net cash used in investing activities | (228,603) | | | (127,076) | |
| Cash flows from financing activities: | | | |
| Proceeds from borrowings under revolving credit facility | 170,000 | | | 320,000 | |
| Repayment of borrowings under revolving credit facility | (195,000) | | | (395,000) | |
| Proceeds from issuance of senior notes | — | | | 170,000 | |
| Debt issuance costs | (8,533) | | | (6,421) | |
| Premiums paid on capped call transactions | — | | | (14,688) | |
| Redemption of senior secured notes | — | | | (127,073) | |
| Proceeds from exercise of stock options | 8 | | | 15 | |
| Restricted stock used for tax withholdings | (1,259) | | | (477) | |
| Net cash used in financing activities | (34,784) | | | (53,644) | |
| Net increase (decrease) in cash, cash equivalents and restricted cash | 191,712 | | | (1,095) | |
| Cash, cash equivalents and restricted cash, beginning of period | 9,935 | | | 8,339 | |
| Cash, cash equivalents and restricted cash, end of period | $ | 201,647 | | | $ | 7,244 | |
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)
| | | | | | | | | | | |
| Six Months Ended June 30, |
| 2022 |
| 2021 |
| Supplemental cash flow information | | | |
| Cash paid for interest | $ | 24,276 | | | $ | 30,124 | |
| Cash paid for income taxes | 600 | | | — | |
| Supplemental non-cash activity | | | |
| Accrued capital expenditures included in accounts payable and accrued expenses | $ | 63,486 | | | $ | 53,096 | |
| Asset retirement obligations incurred, including revisions to estimates | 389 | | | 66 | |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | 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 |
|
| | | | | | | | | | | |
| Six Months Ended June 30, |
| 2022 | | 2021 |
| Cash and cash equivalents | $ | 201,092 | | | $ | 4,702 | |
Restricted cash(1) | 555 | | | 2,542 | |
| Total cash, cash equivalents and restricted cash | $ | 201,647 | | | $ | 7,244 | |
(1) Included in Prepaid and other current assets in the consolidated balance sheet as of June 30, 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 | |
| Restricted stock issued | 2,998 | | | 1 | | | — | | | — | | | 1 | |
| Restricted stock forfeited | (75) | | | — | | | — | | | — | | | — | |
| Stock option exercises | 2 | | | — | | | 7 | | | — | | | 7 | |
| Stock-based compensation - equity awards | — | | | — | | | 6,657 | | | — | | | 6,657 | |
| Net income (loss) | — | | | — | | | — | | | 191,826 | | | 191,826 | |
| Balance at June 30, 2022 | 297,060 | | | 30 | | | $ | 3,024,236 | | | $ | (54,698) | | | $ | 2,969,568 | |
| | | | | | | | | |
| | | | | | | | | |
| | | | | | | | | |
| | | | | | | | | |
| | | | | | | | | |
| | | | | | | | | |
| | | | | | | | | |
| | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | |
| | | | | | | |
| | | | | | |
| 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 | |
| Restricted stock forfeited | (7) | | | — | | | — | | | — | | | — | |
| Stock option exercises | 15 | | | — | | | 15 | | | — | | | 15 | |
| Stock-based compensation - equity awards | — | | | — | | | 4,481 | | | — | | | 4,481 | |
| Net income (loss) | — | | | — | | | — | | | (25,055) | | | (25,055) | |
| Balance at June 30, 2021 | 290,801 | | | 29 | | | $ | 2,998,516 | | | $ | (460,201) | | | $ | 2,538,344 | |
| | | | | | | | | |
| | | | | | | | | |
| | | | | | | | | |
| | | | | | | | | |
| | | | | | | | | |
| | | | | | | | | |
| | | | | | | | | |
| | | | | | | | | |
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 Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2017-01, Business Combinations (Topic 805): Clarifying the Definition of a Business. This update affects all reporting entities and 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 for 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 inhas operating leases for drilling rig contracts, office rental agreements, and other wellhead equipment. During the second quarter of 2017.2022, the Company extended two drilling rig contracts each for a two-year period. A lease right-of-use (ROU) asset and related liability have been recorded based on the present value of the future lease payments over the lease term of the drilling rigs. As of June 30, 2022, $19.0 million was recorded to current operating lease liability and $21.6 million was recorded to noncurrent operating lease liability related to these rigs. There have been no other significant changes in operating leases during the six months ended June 30, 2022. Refer to Note 2—Property Acquisitions for details of15—Leases footnote in 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 relationnotes 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 forconsolidated 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 presentationin Item 8 of the Company’s statements of cash flows and will not have a material impact 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 the income tax consequences, classification of awards as either equity 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 recognize in the statement of financial position a liability to make lease payments (the lease liability) and a right-of-use asset representing its right to use the underlying asset 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 beginning of the earliest period presented using a modified retrospective approach. Although the Company is still in the process of evaluating 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
2021 Annual Report.
CENTENNIAL RESOURCE DEVELOPMENT, INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
Income Taxes
retrospective application using eitherIncome tax expense recognized during interim periods is based on applying an estimated annual effective income tax rate to the Company’s year-to-date income, plus any significant unusual or infrequently occurring items which are recorded in the interim period. The computation of the following methodologies: (i) restatement ofannual estimated effective tax rate at each prior reportinginterim period presented or (ii) recognition of a cumulative-effect adjustment asrequires certain estimates and significant judgment including, but not limited to, the expected operating income for the year, projections of the dateproportion of initial application.income earned and taxed in various state jurisdictions, permanent and temporary differences and the likelihood of recovering deferred tax assets generated. The accounting estimates used to compute the provision for income taxes may change as new events occur, additional information becomes known or as the tax environment changes.
The Company does not expect net income or cash flows to be materially impacted by the new standard, however,
Note 2—Business Combination
Pending Merger with Colgate
On May 19, 2022, the Company entered into a Business Combination Agreement (the “Business Combination Agreement”) with CRP, Colgate Energy Partners III, LLC (“Colgate”), and Colgate Energy Partners III MidCo, LLC (the “Colgate Unitholder”) which provides for the combination of CRP and Colgate in a merger of equals transaction (the “Merger”), with CRP surviving the Merger (the “Surviving Company”) as a subsidiary of Centennial.
Colgate is currently analyzing whether changes to total revenues and total expenses will be necessary to properly reflect revenue for certain pipeline gathering, transportationan independent oil 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 guidancecompany focused on the effective dateacquisition, development, exploration and production 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 asin the Delaware Basin. Colgate owns approximately 105,000 net leasehold acres and 25,000 net royalty acres in Reeves and Ward counties in Texas and Eddy County in New Mexico.
At the effective time of the acquisition date. After settlementMerger, all membership interests in CRP issued and outstanding will be converted into units in the Surviving Company (“Surviving Company Units”) equal to the number of shares of Centennial’s Class A common stock (the “Common Stock”) that are outstanding at such time, and all of the Colgate Unitholder’s membership interest in Colgate will be exchanged for 269,300,000 shares of Class C common stock (with underlying Surviving Company Units) and $525 million in cash. The shares of Class C Common Stock to be issued to the Colgate Unitholders pursuant to the Business Combination Agreement will represent a noncontrolling interest in the Surviving Company.
The transaction has been unanimously approved by the Boards of Directors of both companies. The Company has filed its definitive proxy 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,SEC 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,shareholder meeting is scheduled for August 29, 2022, where the Company acquired interests in 31 producing horizontal wells plus undeveloped acreageMerger will be voted 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 relatingCompany’s shareholders. The Merger is expected to close shortly after 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 allocationshareholder meeting subject to customary closing conditions, including, among others, receipt 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 onrequired approvals from the Company’s previously reported consolidated financial statements, and therefore the Company has not retrospectively adjusted those financial statements.shareholders.
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) | June 30, 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 | $ | 114,168 | | | $ | 57,287 | |
| Joint interest billings, net | | Joint interest billings, net | 26,051 | | | 12,449 | |
| Other | 798 |
| | 2 |
| Other | 1,379 | | | 1,559 | |
| Accounts receivable, net | $ | 50,207 |
| | $ | 14,734 |
| Accounts receivable, net | $ | 141,598 | | | $ | 71,295 | |
Accounts payable and accrued expenses are comprised of the following:
| | | | | | | | | | | |
| (in thousands) | June 30, 2022 | | December 31, 2021 |
| Accounts payable | $ | 31,134 | | | $ | 9,736 | |
| Accrued capital expenditures | 49,791 | | | 24,377 |
| Revenues payable | 60,541 | | | 40,438 |
| Accrued employee compensation and benefits | 9,038 | | | 17,218 |
| Accrued interest | 15,423 | | | 15,259 |
| Accrued derivative settlements payable | 21,168 | | | 8,591 |
| Accrued expenses and other | 21,127 | | | 14,637 |
| Accounts payable and accrued expenses | $ | 208,222 | | | $ | 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 |
|
CENTENNIAL RESOURCE DEVELOPMENT, INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
Note 4—Long-Term Debt
The following table provides information about the Company’s long-term debt as of the dates indicated:
| | | | | | | | | | | |
| (in thousands) | June 30, 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 | (12,152) | | | (13,279) | |
| Unamortized debt discount | (1,798) | | | (1,955) | |
| Senior Notes, net | 801,849 | | | 800,565 | |
| | | |
| Total long-term debt, net | $ | 801,849 | | | $ | 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 SeptemberJune 30, 2017,2022, 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 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 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 itCRP 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)
CENTENNIAL RESOURCE DEVELOPMENT, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
(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 SeptemberJune 30, 2022. In July 2022 in connection with the pending Merger, CRP amended its Credit Agreement; refer to Note 14—Subsequent Events for additional information.
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.
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 June 30, 2022, the net liability recorded related to the Convertible Senior Notes was $164.6 million.
CENTENNIAL RESOURCE DEVELOPMENT, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
Capped Called Transactions
In connection with the issuance of the Convertible Senior Notes in March 2021, CRP entered into privately negotiated capped call spread transactions with option counterparties (the “Capped Call Transactions”). The Capped Call Transactions cover the aggregate number of shares of Common Stock that initially underlie the Convertible Senior Notes and are expected to (i) generally reduce potential dilution to the Common Stock upon a conversion of the Convertible Senior Notes, and/or (ii) offset any cash payments CRP is required to make in excess of the principal amount of the Convertible Senior Notes, subject to a cap. The Capped Call Transactions have an initial strike price of $6.28 per share of Common Stock and an initial capped price of $8.4525 per share of Common Stock, each of which are subject to certain customary adjustments upon the occurrence of certain corporate events, as defined in the capped call agreements.
The cost of the Capped Call Transactions was $14.7 million, which was funded from proceeds from the Convertible Senior Note issuance. The cost to purchase the Capped Call Transactions was recorded to additional paid-in capital in the consolidated balances sheets and will not be subject to remeasurement each reporting period.
Senior Unsecured 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 June 30, 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
CENTENNIAL RESOURCE DEVELOPMENT, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
into agreements that restrict dividends or other payments from their subsidiaries to them; (vii) consolidate, merge or transfer all or substantially all of their assets; (viii) engage in transactions with affiliates; and (ix) create unrestricted subsidiaries. CRP was in compliance with these covenants as of June 30, 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. Note 5—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 ninesix months ended SeptemberJune 30, 2017 (in thousands):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 | 481 | |
| |
| Liabilities divested and settled | (11) | |
| Accretion expense | 533 | |
| Revisions to estimated cash flows | (92) | |
| Asset retirement obligations, end of period | $ | 18,151 | |
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—Stock-Based Compensation
Long Term Incentive Plan
On October 7, 2016,April 27, 2022, the stockholders of the Company approved the second amended and restated Centennial Resource Development, Inc. 2016 Long Term Incentive Plan (the “LTIP”). An aggregate, which, among other things, increased the number of 16,500,000 shares of Class A Common Stock were authorized for issuance under the LTIP,to employees and as of September 30, 2017, the Company had 11,199,857directors from 24,750,000 shares of Class A Common Stock available for future grants.to 44,250,000 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.
|
| | | | | | | |
| (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)
The following table summarizes stock-based compensation expense recognized for the periods presented: | | | | | | | | | | | | | | | | | | | | | | | |
| Three Months Ended June 30, | | Six Months Ended June 30, |
| (in thousands) | 2022 | | 2021 | | 2022 | | 2021 |
| Equity Awards | | | | | | | |
| Restricted stock | $ | 4,481 | | | $ | 3,536 | | | $ | 7,920 | | | $ | 7,142 | |
| Stock option awards | 26 | | | 234 | | | 57 | | | 505 | |
| Performance stock units | 2,079 | | | 646 | | | 4,082 | | | 1,285 | |
Other stock-based compensation expense(1) | 71 | | | 65 | | | 143 | | | 134 | |
| Total stock-based compensation - equity awards | 6,657 | | | 4,481 | | | 12,202 | | | 9,066 | |
| | | | | | | |
| Liability Awards | | | | | | | |
| Restricted stock units | — | | | 4,647 | | | — | | | 7,955 | |
| Performance stock units | (8,593) | | | 10,013 | | | 5,127 | | | 17,119 | |
| Total stock-based compensation - liability awards | (8,593) | | | 14,660 | | | 5,127 | | | 25,074 | |
| | | | | | | |
| Total stock-based compensation expense | $ | (1,936) | | | $ | 19,141 | | | $ | 17,329 | | | $ | 34,140 | |
(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.
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 ninesix months ended SeptemberJune 30, 2017:2022:
| | | | | | | 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 | 2,409,749 | | | 7.90 | |
| Vested | — |
| | $ | — |
| Vested | (387,929) | | | 5.03 | |
| Granted | 841,443 |
| | $ | 17.21 |
| |
| Forfeited | (8,788 | ) | | $ | 18.81 |
| Forfeited | (97,829) | | | 5.40 | |
| Outstanding as of September 30, 2017 | 1,089,252 |
| | $ | 17.86 |
| |
| Unvested balance as of June 30, 2022 | | Unvested balance as of June 30, 2022 | 12,067,678 | | | 3.76 | |
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 six months ended June 30, 2022 and 2021 was $2.0 million and $2.7 million, respectively. Unrecognized compensation cost related to unvested restricted shares at Septemberthat were unvested as of June 30, 20172022 was $15.7$32.4 million, which the Company expects to recognize over a weighted average period of 2.5 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:three years.
|
| | | |
| | 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 | % |
CENTENNIAL RESOURCE DEVELOPMENT, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
The following table provides information about stock option awards outstanding during the ninesix months ended SeptemberJune 30, 2017:2022:
| | | | | | | | | | | | | | | | | | | | | | | |
| 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 | (4,000) | | | 1.92 | | | | | $ | 24 | |
| Forfeited | (2,500) | | | 7.58 | | | | | |
| Expired | (60,832) | | | 14.69 | | | | | |
| Outstanding as of June 30, 2022 | 2,145,466 | | | 15.36 | | | 4.9 | | $ | 276 | |
| Exercisable as of June 30, 2022 | 2,094,791 | | | 15.63 | | | 4.9 | | $ | 165 | |
|
| | | | | | | | | | | | | |
| | 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 six months ended June 30, 2022 and 2021 was $0.2 million and $0.5 million, respectively. The intrinsic value of the stock options exercised was minimal for the six months ended June 30, 2022 and $0.1 million for the six months ended June 30, 2021. As of SeptemberJune 30, 2017,2022, there was $18.9less than $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 2.20.6 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 six months ended June 30, 2022 and the year ended December 31, 2021 there were 0.7 million and 1.1 million shares, respectively, of performance stock units granted that can be settled in either Common Stock or cash upon vesting at the Company’s discretion. The Company currently intends to settle these performance stock units in Common Stock and has sufficient shares available under the LTIP to settle the units in Common Stock at the potential future vesting dates. Accordingly, these units have been treated as equity-based awards and a grant date was established on April 27, 2022, which represents the date the 2022 awards were approved and the date sufficient shares become available under the LTIP to settle 2021 awards in Common Stock. As a result, these PSU awards’ fair value was determined as of the grant date and remeasurement of such value will not be required.
The grant-date fair value was estimated using a Monte Carlo valuation model. 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,the Company’s Common Stock, and the risk-free interest rate is based on U.S. Treasury yield curve rates with maturities consistent with the three-year vesting 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:units: | | | | | | | | | | | | | | |
| | 2021 Awards | | 2022 Awards |
| Weighted average fair value per share | | $12.79 | | $13.81 |
| Number of simulations | | 10,000,000 | | 10,000,000 |
| Expected implied stock volatility | | 99.5% | | 96.3% |
| Dividend yield | | —% | | —% |
| Risk-free interest rate | | 2.3% | | 2.7% |
CENTENNIAL RESOURCE DEVELOPMENT, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
|
| | | |
| | Nine Months Ended September 30, 2017 |
Number of simulations | | 1,000,000 |
|
Expected stock volatility | | 41.6 | % |
Dividend yield | | — | % |
Risk-free interest rate | | 1.5 | % |
The following table provides information about performance stock units outstanding during the ninesix months ended SeptemberJune 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 |
|
| | | | | | | | | | | |
| Awards | | Weighted Average Fair Value |
| Unvested balance as of December 31, 2021 | 1,580,980 | | | $ | 8.54 | |
| Granted | 733,330 | | | 13.81 | |
| Vested | — | | | — | |
| Cancelled | — | | | — | |
| Forfeited | — | | | — | |
| Unvested balance as of June 30, 2022 | 2,314,310 | | | 11.83 | |
As of SeptemberJune 30, 2017,2022, there was $3.9$19.1 million of unrecognized compensation cost related to PSUs that were unvested, performance stock units, which the Company expects to recognize on a pro ratapro-rata basis over a weighted average period of 2.752.4 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 Company 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 June 30, 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 June 30, 2022, there was $15.2 million of unrecognized compensation cost that represents the unvested portion of the fair value of the PSUs at June 30, 2022 and will be recognized over a weighted average period of 1.0 years.
CENTENNIAL RESOURCE DEVELOPMENT, INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
Liability Awards Fair Value
The fair value of the PSUs was estimated using a Monte Carlo valuation model as of the balance sheet date. The Monte Carlo valuation model is based on random projections of stock price paths and must be repeated numerous times to achieve a probabilistic assessment. Expected volatility was calculated based on the historical volatility of the Company’s Common Stock as well as the peer companies that are specified in the PSU award agreement. The risk-free rate is based on U.S. Treasury yield curve rates with maturities consistent with the remaining vesting or performance period.
The following table summarizes the key assumptions and related information used to determine the fair value of the liability awards as of June 30, 2022: | | | | | | | | |
| | Performance stock units |
| | |
| Number of simulations | | 10,000,000 |
| Expected implied stock volatility | | 73.7% |
| Dividend yield | | —% |
| Risk-free interest rate | | 2.8% |
Note 7—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 SeptemberJune 30, 2017:2022: | | | | | | | | | | | | | | | | | | | | | | | |
| Period | | Volume (Bbls) | | Volume
(Bbls/d) | | Wtd. Avg. Crude Price ($/Bbl)(1) |
| Crude oil swaps | 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 | July 2022 - September 2022 | | 460,000 | | | 5,000 | | | $78.00 | - | $107.13 |
| October 2022 - December 2022 | | 644,000 | | | 7,000 | | | 80.00 | - | 104.17 |
| January 2023 - March 2023 | | 810,000 | | | 9,000 | | | 75.56 | - | 91.15 |
| April 2023 - June 2023 | | 819,000 | | | 9,000 | | | 75.56 | - | 91.15 |
| July 2023 - September 2023 | | 644,000 | | | 7,000 | | | 76.43 | - | 92.70 |
| October 2023 - December 2023 | | 644,000 | | | 7,000 | | | 76.43 | - | 92.70 |
| | | | | | | | | |
| | | | | | | | | |
| | | | | | | | | |
CENTENNIAL RESOURCE DEVELOPMENT, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
|
| | | | | | | | |
| | Period | | Volume (Bbl) | | Weighted Average Fixed Price/Differential ($/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. Differential ($/Bbl)(3) |
| Crude oil basis differential swaps | 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 | July 2022 - September 2022 | | 920,000 | | | 10,000 | | | $0.71 |
| October 2022 - December 2022 | | 920,000 | | | 10,000 | | | 0.71 |
| | | | | | | |
(1) These crude oil swap transactions are settled based on the NYMEX WTI index price on each trading day within the specified monthly settlement period versus the contractual swap price for the volumes stipulated.
(2) These crude oil collars are settled based on the NYMEX WTI index price on each trading day within the specified monthly settlement period versus the contractual floor and ceiling prices for the volumes stipulated.
(3) These crude oil basis swap transactions are settled based on the difference between the arithmetic average of ARGUS MIDLAND WTI and ARGUS WTI CUSHING indices, during each applicable monthly settlement period.
(4) These crude oil roll swap transactions are settled based on the difference between the arithmetic average of NYMEX WTI calendar month prices and the physical crude oil delivery month price. | | | | | | | | | | | | | | | | | | | | | | | |
| Period | | Volume (MMBtu) | | Volume (MMBtu/d) | | Wtd. Avg. Gas Price ($/MMBtu)(1) |
| Natural gas swaps | 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 | 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 | July 2022 - September 2022 | | 1,840,000 | | | 20,000 | | | $3.50 | - | $3.97 |
| October 2022 - December 2022 | | 2,450,000 | | 26,630 | | | 3.87 | - | 5.06 |
| January 2023 - March 2023 | | 4,950,000 | | 55,000 | | | 4.09 | - | 7.47 |
| April 2023 - June 2023 | | 4,095,000 | | 45,000 | | | 3.72 | - | 7.32 |
| July 2023 - September 2023 | | 4,140,000 | | 45,000 | | | 3.72 | - | 7.32 |
| October 2023 - December 2023 | | 4,140,000 | | 45,000 | | | 3.76 | - | 7.69 |
| January 2024 - March 2024 | | 1,820,000 | | 20,000 | | | 3.25 | - | 5.31 |
| | | | | | | | | |
| |
(1)
| The oil swap contracts are settled based on the month’s average daily NYMEX price of West Texas Intermediate Light Sweet Crude. The oil basis swap contracts are settled based on the difference between the arithmetic average of WTI MIDLAND ARGUS and WTI ARGUS during the relevant calculation period. |
|
| | | | | | | | |
| | Period | | Volume (MMBtu) | | Weighted Average Fixed Price/Differential ($/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.
CENTENNIAL RESOURCE DEVELOPMENT, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
(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.
CENTENNIAL RESOURCE DEVELOPMENT, INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
The following table presents gains and losses forthe impact of the Company’s derivative instruments not designated as hedges for accounting purposesin its consolidated statements of operations for the periods presented:
| | | | | | | | | | | | | | | | | | | | | | | |
| Three Months Ended June 30, | | Six Months Ended June 30, |
| (in thousands) | 2022 | | 2021 | | 2022 | | 2021 |
| | | | | | | |
| | | | | | | |
| Net gain (loss) on derivative instruments | $ | (34,134) | | | $ | (54,959) | | | $ | (163,657) | | | $ | (106,158) | |
|
| | | | | | | | | | | | | | | | | | |
| | 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) | | | June 30, 2022 |
| Derivative Assets | | | | | | | |
| Commodity contracts | Prepaid and other current assets | | $ | 26,356 | | | $ | (26,211) | | | $ | 145 | |
| Other noncurrent assets | | 21,874 | | | (17,995) | | | 3,879 | |
| Derivative Liabilities | | | | | | | |
| Commodity contracts | Derivative instruments | | 109,752 | | | (26,211) | | | 83,541 | |
| Other noncurrent liabilities | | 20,518 | | | (17,995) | | | 2,523 | |
| | | | | | | |
| | | 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.
CENTENNIAL RESOURCE DEVELOPMENT, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
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.
Note 8—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 |
| June 30, 2022 | | | | | |
| Total assets | $ | — | | | $ | 4,024 | | | $ | — | |
| Total liabilities | — | | | 86,064 | | | — | |
| 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
CENTENNIAL RESOURCE DEVELOPMENT, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
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.
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—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:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | June 30, 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) | | 286,083 | | | 289,448 | | | 264,129 | | | 285,666 | | | 289,448 | | | 286,554 | |
6.875% Senior Notes due 2027(2) | | 351,164 | | | 356,351 | | | 337,643 | | | 350,712 | | | 356,351 | | | 361,696 | |
3.25% Convertible Notes due 2028(2) | | 164,602 | | | 170,000 | | | 212,577 | | | 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—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 issuedsix months ended June 30, 2022. Due to restrictions related to the Centennial Contributors in connection withMerger, 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 of March 31, 2017, due to the issuance of 23.5 million shares of Class A Common Stock on June 8, 2017. The Company has consolidatedbeen unable to make or initiate any share repurchases under the financial positionRepurchase Program since the announcement and results of operations of CRP and reflected that portion retained bytherefore, will not be able to begin repurchasing its shares until 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.pending Merger closes or is otherwise terminated.
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.
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—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
CENTENNIAL RESOURCE DEVELOPMENT, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
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 June 30, | | Six Months Ended June 30, |
| (in thousands, except per share data) | 2022 | | 2021 | | 2022 | | 2021 |
| Net income (loss) | $ | 191,826 | | | $ | (25,055) | | | $ | 207,628 | | | $ | (59,700) | |
| Add: Interest on Convertible Senior Notes, net of tax | 1,306 | | | — | | | 2,611 | | | — | |
| Adjusted net income (loss) | $ | 193,132 | | | $ | (25,055) | | | $ | 210,239 | | | $ | (59,700) | |
| | | | | | | |
| Basic weighted average shares of Common Stock outstanding | 284,992 | | | 279,185 | | | 284,922 | | | 279,061 | |
| Add: Dilutive effects of equity awards and ESPP shares | 8,038 | | | — | | | 7,897 | | | — | |
| Add: Dilutive effects of Convertible Senior Notes | 27,074 | | | — | | | 27,074 | | | — | |
| Diluted weighted average shares of Common Stock outstanding | 320,104 | | | 279,185 | | | 319,893 | | | 279,061 | |
| | | | | | | |
| Basic net earnings (loss) per share of Common Stock | $ | 0.67 | | | $ | (0.09) | | | $ | 0.73 | | | $ | (0.21) | |
| Diluted net earnings (loss) per share of Common Stock | $ | 0.60 | | | $ | (0.09) | | | $ | 0.66 | | | $ | (0.21) | |
|
| | | | | | | |
| (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 June 30, | | Six Months Ended June 30, |
| (in thousands) | 2022 | | 2021(1) | | 2022 | | 2021(1) |
| Out-of-the-money stock options | 2,049 | | | 2,241 | | | 2,073 | | | 2,267 | |
| Restricted stock | — | | | 8,769 | | | — | | | 9,167 | |
| Performance stock units | — | | | — | | | 224 | | | 199 | |
| Employee Stock Purchase Plan | — | | | 68 | | | — | | | 54 | |
| Convertible Senior Notes | — | | | 27,074 | | | — | | | 27,074 | |
| Warrants | — | | | 8,000 | | | — | | | 8,000 | |
(1) The Company recognized a net loss during the three and six months ended June 30, 2021, and therefore all potentially dilutive securities were out-of-the-money, as there effect was anti-dilutive and excluded from the calculation of diluted net earnings per share.
Note 11—Transactions with Related Parties
Riverstone Investment Group LLC and its affiliates (“Riverstone”) beneficially own a more than 10% equity interest in the Company and are therefore considered related parties. The Company has a marketing agreement with Lucid Energy Delaware, LLC (“Lucid”), an affiliate of Riverstone. The Company believes that the terms of the marketing agreement with Lucid are no less favorable to either party than those held with unaffiliated parties.
The following table summarizes the revenues recognized and the associated processing fees incurred from this marketing agreement as included in the consolidated statements of operations for the nine months ended September 30, 2017,periods indicated, as well as the diluted earnings per share calculation excludes 1.0 million stock options that were out-of-the-money,related net receivables outstanding as there effect was anti-dilutive.of the balance sheet dates:
| | | | | | | | | | | | | | | | | | | | | | | |
| Three Months Ended June 30, | | Six Months Ended June 30, |
| (in thousands) | 2022 | | 2021 | | 2022 | | 2021 |
| Oil and gas sales | $ | 9,107 | | | $ | 3,056 | | | $ | 18,590 | | | $ | 4,132 | |
| Gathering, processing and transportation expenses | 2,150 | | | 1,636 | | | 4,669 | | | 2,841 | |
| | | | | | | | | | | |
| (in thousands) | June 30, 2022 | | December 31, 2021 |
Accounts receivable, net(1) | $ | 3,889 | | | $ | 5,562 | |
(1) Represents amounts due from Lucid and are presented net of unpaid processing fees as of the indicated period end date.
CENTENNIAL RESOURCE DEVELOPMENT, INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
Note 12—Transactions with Related Parties
Customer and Supplier Relationships
Riverstone Affiliated Companies. Riverstone and its affiliates, including our Sponsor, beneficially own more than 10% of our equity interest 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, the 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 affiliated 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, LLC, an affiliate of NGP. In addition, the Company paid approximately $3.3 million during the nine months ended September 30, 2016 (Predecessor), to RockPile Energy Services, LLC (“Rockpile”). On July 3, 2017, Rockpile was acquired by an unrelated third party and is no longer an affiliate of NGP.
Note 13—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, there havesix months ended June 30, 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 $39.1 million, which represents the minimum financial commitment pursuant to the terms of the contract from June 30, 2022 through March 31, 2024. There has been no other material, non-routine changes in commitments during the ninesix months ended SeptemberJune 30, 2017.2022. 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.
Note 13—Revenues
Revenue from Contracts with Customers
Crude oil, natural gas and NGL sales are recognized at the point that control of the product is transferred to the customer and collectability is reasonably assured. Virtually all of the Company’s contract pricing provisions are tied to a market index, with certain adjustments based on, among other factors, transportation costs to an active spot market and quality differentials. As a result, the Company’s realized prices of oil, natural gas, and NGLs fluctuate to remain competitive with other available oil, natural gas, and NGLs supplies both globally (in the case of crude oil) and locally.
Oil and gas revenues presented within the consolidated statements of operations relate to the sale of oil, natural gas and NGLs as shown below:
| | | | | | | | | | | | | | | | | | | | | | | |
| Three Months Ended June 30, | | Six Months Ended June 30, |
| 2022 | | 2021 | | 2022 |
| 2021 |
| Operating revenues (in thousands): | | | | | | | |
| Oil sales | $ | 349,591 | | | $ | 177,105 | | | $ | 612,358 | | | $ | 310,831 | |
| Natural gas sales | 68,030 | | | 27,015 | | | 107,048 | | | 62,466 | |
| NGL sales | 55,033 | | | 28,457 | | | 100,525 | | | 51,671 | |
| Oil and gas sales | $ | 472,654 | | | $ | 232,577 | | | $ | 819,931 | | | $ | 424,968 | |
CENTENNIAL RESOURCE DEVELOPMENT, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
Oil sales
The Company’s crude oil sales contracts are generally structured whereby oil is delivered to the purchaser at a contractually agreed-upon delivery point at which the purchaser takes title of the product. This delivery point is usually at the wellhead or at the inlet of a transportation pipeline. Revenue is recognized when control transfers to the purchaser at the delivery point based on the net price received from the purchaser. Any downstream transportation costs incurred by crude purchasers are reflected as a net reduction to oil sales revenues.
Natural gas and NGL sales
Under the Company’s natural gas processing contracts, liquids rich natural gas is delivered to a midstream gathering and processing entity at the inlet of the gas 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 generally elects to take its residue gas product “in-kind” at the plant tailgate. For these contracts, the Company evaluates when control is transferred and revenue should be recognized. Where the Company has concluded that control transfers at the tailgate of the processing facility, fees incurred prior to transfer of control are presented as gathering, processing and transportation expenses (“GP&T”) within the consolidated statements of operations. Any transportation and fractionation costs incurred subsequent to the point of transfer of control are reflected as a net reduction to natural gas and NGL sales revenues presented in the table above.
Performance obligations
For all commodity products, the Company records revenue in the month production is delivered to the purchaser. Settlement statements for natural gas and NGL sales may not be received for 30 to 90 days after the date production volumes are delivered and for crude oil, generally within 30 days after delivery has occurred. However, payment is unconditional once the performance obligations have been satisfied. At such time, the volumes delivered and sales prices can be reasonably estimated and amounts due from customers are accrued in Accounts receivable, net in the consolidated balance sheets. As of June 30, 2022 and December 31, 2021, such receivable balances were $114.2 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 and six months ended June 30, 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 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 14—Subsequent Events
Credit Facility Amendment
In connection with the October 2017 semi-annual redetermination, on November 2, 2017,On July 15, 2022, CRP and the Company entered into the fifthfirst amendment to its Credit Agreement (the “Amendment”). The Amendment, among other things, waives compliance with certain restrictive covenants and provides the restated credit agreementlenders’ consent to increasea planned Pre-Merger Reorganization (as defined within the Amendment) in order to enable the Merger. In addition, the Amendment increases the elected commitments under the Credit Agreement to $1.5 billion from $750 million and the borrowing base to $2.5 billion from $350.0 million$1.15 billion. The Amendment is subject to $575.0 million.and effective as of the closing date of the Merger and will be terminated if the Merger has not occurred prior to November 30, 2022.
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, the success of our pending merger transaction, 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 this Quarterly Report and 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 half 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. Despite governmental actions from several countries to release a portion of their strategic petroleum reserves, 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 half 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 $9.46 per MMBtu on June 9, 2022, from a low of $1.33 per MMBtu 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 | | Q2 | | |
| Crude oil (per Bbl) | $ | 46.19 | | | $ | 28.00 | | | $ | 40.93 | | | $ | 42.66 | | | $ | 57.84 | | | $ | 66.06 | | | $ | 70.56 | | | $ | 77.09 | | | $ | 94.40 | | | $ | 108.34 | | | |
| Natural gas (per MMBtu) | $ | 1.88 | | | $ | 1.65 | | | $ | 1.95 | | | $ | 2.47 | | | $ | 3.44 | | | $ | 2.88 | | | $ | 4.28 | | | $ | 4.74 | | | $ | 4.60 | | | $ | 7.39 | | | |
Lower commodity prices in the future couldand 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 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 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 operational disruptions, including disruptions from our suppliers or service providers, as a result of the COVID-19 outbreak.
2022 Highlights and Future Considerations
Pending Merger
On May 19, 2022, we entered into a Business Combination Agreement (the “Business Combination Agreement”) with Colgate Energy Partners III, LLC (“Colgate”), which provides for the combination of Centennial and Colgate in a merger of equals transaction (the “Merger”). Colgate is an independent oil and gas company focused on the acquisition, development, exploration and production of oil and natural gas prices may resultproperties in the Permian Basin. Colgate owns approximately 105,000 net leasehold acres and 25,000 net royalty acres in Reeves and Ward counties in Texas and Eddy County in New Mexico. We believe that the Merger will provide significant non-cash fair value losses being incurredincreases to operational and financial scale, drive accretion across our key financial and operating metrics, and enhance the combined company’s shareholder returns.
Pursuant to the Business Combination Agreement, all membership interests in CRP issued and outstanding will be converted into units in the surviving company (“Surviving Company Units”) equal to the number of shares of our Class A common stock (“Common Stock”) that are outstanding at such time, and all of the membership interest in Colgate will be exchanged for 269,300,000 shares of Class C common stock (with underlying Surviving Company Units) and $525 million in cash. The shares of Class C common stock will represent a noncontrolling interest in the Surviving Company.
The transaction has been unanimously approved by the Boards of Directors of both companies. The definitive proxy statement has been filed with the SEC and the shareholder meeting is scheduled for August 29, 2022, where the Merger will be voted on by our derivatives, which could cause usshareholders. The Merger is expected to experience net losses when oil and natural gas prices rise.
2017 Highlights and Future Considerationsclose shortly after the shareholder meeting subject to customary closing conditions, including, among others, receipt of the required approvals from our shareholders.
Operational Highlights
We operated a two-rig drilling program during the first six rig program,months of 2022, which allowedenabled us to spud 22complete and bring online 31 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 5,8009,100 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 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 these share repurchases with cash on hand and cash flows from operations. Due to restrictions related to the majorityMerger, we have been unable to make or initiate any share repurchases under the Repurchase Program since the announcement and therefore, we will not be able to begin repurchasing our shares until the pending Merger closes or is otherwise terminated.
In connection with the October 2017 semi-annual redetermination, on November 2, 2017, the CompanyOn July 15, 2022, we entered into the fifthfirst amendment to our Credit Agreement (the “Amendment”). The Amendment, among other things, waives compliance with certain restrictive covenants and provides the restated credit agreementlenders’ consent to increasea planned Pre-Merger Reorganization (as defined within the Amendment) in order to enable the Merger. In addition, the Amendment increases the elected commitments under our Credit Agreement to $1.5 billion from $750 million and the borrowing base to $2.5 billion from $350.0 million$1.15 billion. The Amendment is subject to $575.0 million.and effective as of the closing date of the Merger and will be terminated if the Merger has not occurred prior to November 30, 2022.
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 SeptemberJune 30, 2017 (Successor)2022 Compared to Three Months Ended SeptemberJune 30, 2016 (Predecessor)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 June 30, | | Increase/(Decrease) |
| 2022 | | 2021 | | $ | | % |
| Net revenues (in thousands): | | | | | | | |
| Oil sales | $ | 349,591 | | | $ | 177,105 | | | $ | 172,486 | | | 97 | % |
| Natural gas sales | 68,030 | | | 27,015 | | | 41,015 | | | 152 | % |
| NGL sales | 55,033 | | | 28,457 | | | 26,576 | | | 93 | % |
| Oil and gas sales | $ | 472,654 | | | $ | 232,577 | | | $ | 240,077 | | | 103 | % |
| | | | | | | |
| Average sales prices: | | | | | | | |
| Oil (per Bbl) | $ | 104.69 | | | $ | 60.99 | | | $ | 43.70 | | | 72 | % |
| Effect of derivative settlements on average price (per Bbl) | (16.97) | | | (12.59) | | | (4.38) | | | (35) | % |
| Oil net of hedging (per Bbl) | $ | 87.72 | | | $ | 48.40 | | | $ | 39.32 | | | 81 | % |
| | | | | | | |
| Average NYMEX price for oil (per Bbl) | $ | 108.34 | | | $ | 66.06 | | | $ | 42.28 | | | 64 | % |
| Oil differential from NYMEX | (3.65) | | | (5.07) | | | 1.42 | | | 28 | % |
| | | | | | | |
| Natural gas (per Mcf) | $ | 6.22 | | | $ | 2.55 | | | $ | 3.67 | | | 144 | % |
| Effect of derivative settlements on average price (per Mcf) | (1.55) | | | (0.09) | | | (1.46) | | | (1,622) | % |
| Natural gas net of hedging (per Mcf) | $ | 4.67 | | | $ | 2.46 | | | $ | 2.21 | | | 90 | % |
| | | | | | | |
| Average NYMEX price for natural gas (per Mcf) | $ | 7.39 | | | $ | 2.88 | | | $ | 4.51 | | | 157 | % |
| Natural gas differential from NYMEX | (1.17) | | | (0.33) | | | (0.84) | | | (255) | % |
| | | | | | | |
| NGL (per Bbl) | $ | 44.77 | | | $ | 30.37 | | | $ | 14.40 | | | 47 | % |
| | | | | | | |
| Net production: | | | | | | | |
| Oil (MBbls) | 3,339 | | | 2,904 | | | 435 | | | 15 | % |
| Natural gas (MMcf) | 10,941 | | | 10,613 | | | 328 | | | 3 | % |
| NGL (MBbls) | 1,230 | | | 937 | | | 293 | | | 31 | % |
Total (MBoe)(1) | 6,392 | | | 5,610 | | | 782 | | | 14 | % |
| | | | | | | |
| Average daily net production: | | | | | | | |
| Oil (Bbls/d) | 36,696 | | | 31,912 | | | 4,784 | | | 15 | % |
| Natural gas (Mcf/d) | 120,225 | | | 116,629 | | | 3,596 | | | 3 | % |
| NGL (Bbls/d) | 13,507 | | | 10,297 | | | 3,210 | | | 31 | % |
Total (Boe/d)(1) | 70,240 | | | 61,647 | | | 8,593 | | | 14 | % |
| |
(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 SeptemberJune 30, 2017 (Successor)2022 were $84.3$240.1 million (or 309%103%) higher than total net revenues for the three months ended SeptemberJune 30, 2016 (Predecessor). Our revenues2021. 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 second quarter of 2022 compared to the same 2021 period by 72%, 144% and 47%, respectively. The 72% increase in the average realized oil price was mainly the result of higher (64%) NYMEX crude prices between periods, as well as improved oil differentials ($1.42 per Bbl narrower). The average realized sales price of natural gas increased 144% due to higher (157%) NYMEX gas prices between periods, partially offset by wider gas differentials ($0.84 per Mcf wider). The 47% increase in average realized NGL prices between periods was primarily attributable to higher Mont Belvieu spot prices for plant products in the second quarter of 2022 as compared to the second quarter of 2021. The market prices for oil, natural gas and NGLs have all been impacted by global supply constraints for oil and gas throughout 2021 and 2022, as well as increasing demand worldwide as global economies emerge from COVID-19 era lockdowns and restrictions, as discussed in the market conditions section above.
Net production volumes for oil, natural gas and NGLs increased 246%15%, 381%3% and 397%31%, respectively, between periods. The increase in oil volume increase between periodsproduction 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 thirdsecond quarter of 2016,2021, we placed 49 operated50 wells on production, in the Delaware Basin, which added 1,4161,649 MBbls of net oil production to the thirdthree months ended June 30, 2022, as compared to 28 wells brought online since the second quarter of 2017. The increase in our operated well count is attributable2020 that added 872 MBbls of net oil production to the ramp up of our drilling program starting in the fourthsecond quarter of 2016.2021. These oil volume increases were partially offset by normal production declinesdecline 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, the main processor of our raw gas and NGL volumes were also impacted byoperated in partial ethane-recovery during the acreage we acquired from Silverback, which has a higher gas/oil ratio. During the thirdsecond 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 June 30, | | Increase/(Decrease) |
| 2022 | | 2021 | | Change | | % |
| Operating costs (in thousands): | | | | | | | |
| Lease operating expenses | $ | 28,900 | | | $ | 22,976 | | | $ | 5,924 | | | 26 | % |
| Severance and ad valorem taxes | 34,695 | | | 15,784 | | | 18,911 | | | 120 | % |
| Gathering, processing and transportation expenses | 25,756 | | | 19,494 | | | 6,262 | | | 32 | % |
| Operating cost metrics: | | | | | | | |
| Lease operating expenses (per Boe) | $ | 4.52 | | | $ | 4.10 | | | $ | 0.42 | | | 10 | % |
| Severance and ad valorem taxes (% of revenue) | 7.3 | % | | 6.8 | % | | 0.5 | % | | 7 | % |
| Gathering, processing and transportation expenses (per Boe) | $ | 4.03 | | | $ | 3.47 | | | $ | 0.56 | | | 16 | % |
|
| | | | | | | | | | | | | | | |
| | 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 SeptemberJune 30, 2017 (Successor)2022 increased $7.7$5.9 million compared to the three months ended SeptemberJune 30, 2016 (Predecessor).2021. Higher LOE for the thirdsecond quarter of 20172022 was primarily related to (i) a $6.0$2.9 million increase associated with a higher well count. We added 49 gross wells through successful drilling and 57 gross wells fromin electricity costs between periods due to electricity credits received during the Silverback and GMT Acquisitions. In addition,second quarter of 2021 related to the severe winter storm in the Permian Basin (“Winter Storm Uri”) that were not similarly received in 2022; (ii) an increase in workover activity increased $1.7expense of $0.9 million between periods as a result ofperiods; and (iii) higher fixed and variable costs associated with our higher well count. We had 65count, which increased to 435 gross operated horizontal wells as of SeptemberJune 30, 2016 as compared to 1712022 from 409 gross operated horizontal wells as of SeptemberJune 30, 2017.2021. These increases were partially offset by lower water handling costs, which are associated with our higher level of recycling activity whereby produced water from our operated wells is recycled and then reused in our drilling and completion operations. This process results in significantly lower costs as compared to typical water disposal rates.
Our LOE on a per Boe basis, on the other hand, decreased when comparing the third quarter of 2017 to the same 2016 period. LOE per Boe was $3.56$4.52 for the thirdsecond quarter of 2017,2022, which represents a decreasean increase of $0.91$0.42 per Boe (or 20%10%) from the thirdsecond quarter of 2016.2021. This decrease in rateincrease was mainly due to flush production from new wells we drilledprimarily driven by per Boe increases associated with (i) higher electricity expenses between periods (discussed above); (ii) higher workover expense; and completed over the past 12 months, which has the effect of reducing(iii) fixed and semi-variable costs, onsuch as monthly equipment rentals, repair work, labor, and wellhead chemical costs, that increase at a higher rate than increases in production. These per Boe basis.increases were partially offset by decreases in our water handling costs described above.
Severance and Ad Valorem Taxes. Severance and ad valorem taxes for the three months ended June 30, 2022 increased $18.9 million compared to the three months ended June 30, 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)
second quarter of 2022 increased $5.0$17.6 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 $1.3 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 7.3% for the three months ended SeptemberJune 30, 20172022 as compared to 5.2%6.8% 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 via the GMT Acquisition which carry alevies higher severance tax raterates than Texas, during the second quarter of 8.8%.2022.
Gathering, Processing and Transportation Expenses. Gathering, processing and transportation expenses (“GP&T”) for the three months ended SeptemberJune 30, 2017 (Successor)2022 increased $8.1$6.3 million as compared to the three months ended SeptemberJune 30, 2016 (Predecessor) due2021. Similarly, GP&T increased on a per Boe basis from $3.47 for the second quarter of 2021 to $4.03 for the second quarter of 2022. These increases were mainly attributable to 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 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 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.discussed above. This increase was primarily the resultpartially offset by a higher portion of a new firm transportation agreement we entered intoour 2022 oil and gas volumes being produced from our New Mexico wells, where our GP&T rates are currently lower than those 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).Texas.
Depreciation, Depletion and Amortization. The following table summarizes our depreciation, depletion and amortization (“DD&A&A”) for the periods indicated:
| | | | | | | | | | | |
| Three Months Ended June 30, |
| (in thousands, except per Boe data) | 2022 |
| 2021 |
| Depreciation, depletion and amortization | $ | 82,117 | | | $ | 73,429 | |
| Depreciation, depletion and amortization per Boe | $ | 12.85 | | | $ | 13.09 | |
|
| | | | | | | | |
| | 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 $12.85 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 thirdsecond 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$13.09 for the same period in 2016. The primary factor contributing to this lower2021. This decrease in DD&A rate was substantial additionsprimarily due to our proved reservesthe Company continuing to complete wells with low finding and development costs and high quantities of associated 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 thirdsecond 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, 2016.2021.
General and Administrative Expenses. The following table summarizes our general and administrative (“G&A”) expenses for the periods indicated:
| | | | Successor | | | Predecessor | | Three Months Ended June 30, |
| (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 | $ | 12,434 | | | $ | 10,126 | |
| Stock-based compensation - equity awards | | Stock-based compensation - equity awards | 6,106 | | | 4,260 | |
| Stock-based compensation - liability awards | | Stock-based compensation - liability awards | (8,593) | | | 14,421 | |
| General and administrative expenses | $ | 13,311 |
| | | $ | 4,848 |
| General and administrative expenses | 9,947 | | | 28,807 | |
G&A expenses for the three months ended SeptemberJune 30, 2017 (Successor)2022 were $9.9 million compared to $28.8 million for the three months ended June 30, 2021. Lower G&A in the second quarter of 2022 was the result of a $21.2 million decrease in total stock-based compensation expense between periods. This decrease was primarily related to performance stock units granted in 2020 that are recorded at their respective fair value each balance sheet date, and such fair value decreased between periods. This decrease was slightly offset by an increase in cash G&A, which increased $8.5$2.3 million period over period due to higher payroll and other personnel costs.
Merger and integration expense. Merger and integration expense for the same 2016three months ended June 30, 2022 was $5.7 million and includes costs incurred for the pending Merger consisting primarily of legal and advisory fees. See Note 2—Business Combination for further details regarding the pending Merger.
Impairment and Abandonment Expense. During the three months ended June 30, 2022, impairment and abandonment expense was $0.5 million as compared to $9.2 million during the three months ended June 30, 2021. Both periods consist 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 June 30, |
| (in thousands) | 2022 |
| 2021 |
| Geological and geophysical costs | $ | 1,534 | | | $ | 1,173 | |
| Stock-based compensation - equity awards | 551 | | | 221 | |
| Stock-based compensation - liability awards | — | | | 239 | |
| | | |
| Other expenses | (131) | | | 131 | |
| Exploration and other expenses | $ | 1,954 | | | $ | 1,764 | |
Exploration and other expenses were $2.0 million for the three months ended June 30, 2022 compared to $1.8 million for the three months ended June 30, 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 (Predecessor). Thisover period increase was primarily duerelated to $5.9 millionhigher G&G personnel costs in higher employee salaries and related costs between periods and $3.4 million of stock-based compensation incurred during the thirdsecond 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 June 30, |
| (in thousands) | 2022 | | 2021 |
| Credit facility | $ | 772 | | | $ | 2,762 | |
| 8.00% Senior Secured Notes due 2025 | — | | | 367 | |
| 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 | | | 1,381 | |
| Amortization of debt issuance costs and debt discount | 2,734 | | | 1,040 | |
| Interest capitalized | (575) | | | (382) | |
| Total | $ | 14,326 | | | $ | 15,182 | |
|
| | | | | | | | |
| | 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 $0.9 million for the three months ended SeptemberJune 30, 2017 (Successor), we incurred $1.5 million in interest related2022 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 SeptemberJune 30, 2016 (Predecessor), we recorded $1.02021 primarily due to (i) $2.0 million in lower interest incurred on our Credit Agreement due to lower borrowings outstanding during the 2022 period, and (ii) $0.4 million in interest expense on our Senior Secured Notes due 2025 that was incurred in the second quarter of 2021 but not in the 2022 period, as these notes were redeemed in April of 2021. These decreases were partially offset by additional debt issuance costs amortized during the second quarter of 2022 related to CRP’s credit facility and $1.0 millionfees incurred for an incremental commitment letter we entered into in interest related to CRP’s term loan, which was extinguished uponconnection with the closing of the Business Combination. Merger.
Our weighted average debtborrowings outstanding during the third quarter of 2017 was $108.5under our Credit Agreement were $5.4 million versus $124.0$289.8 million for the third quarter of 2016.three months ended June 30, 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%2.7% and 3.3% for the third quarterthree months ended June 30, 2022 and 2021, respectively.
Gain (loss) on extinguishment of 2016.debt. During the three months ended June 30, 2021, we redeemed at par all of our $127.1 million aggregate principal amount of Senior Secured Notes outstanding. In connection with this redemption, we recorded a loss on debt extinguishment of $22.2 million related to the write-off of all unamortized debt issuance costs and debt discounts associated with these notes.
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 ofon any closed out hedge positions during the period.
The following table presents gains and losses on our hedged derivative positions. Forinstruments for the three month periods ended September 30, 2017 (Successor) and 2016 (Predecessor), we recognized non-cash mark-to-market derivative losses of $1.3 million and $0.2 million, respectively. Cash derivative settlements, on the other hand, amounted to $0.4 million and $2.0 million in gains for both the third quarters of 2017 and 2016, respectively.indicated:
| | | | | | | | | | | |
| Three Months Ended June 30, |
| (in thousands) | 2022 | | 2021 |
| Realized cash settlement gains (losses) | $ | (73,648) | | | $ | (37,513) | |
| Non-cash mark-to-market derivative gain (loss) | 39,514 | | | (17,446) | |
| Total | $ | (34,134) | | | $ | (54,959) | |
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 June 30, |
| (in thousands) | 2022 | | 2021 |
| Income (loss) before income taxes | $ | 233,313 | | | $ | (25,055) | |
| Income tax (expense) benefit | (41,487) | | | — | |
Our provisions for income taxes for the three months ended SeptemberJune 30, 2017 differed2022 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.
For the three months ended June 30, 2022, we generated pre-tax net income of $233.3 million and recorded income tax expense of $41.5 million. The primary factor decreasing our income tax expense below the U.S. statutory rate was the partial release of our deferred tax valuation allowance due to the generation of net income in the current year.
NineFor the three months ended June 30, 2021, we recognized a deferred tax asset valuation allowance of $7.6 million against net operating losses (“NOLs”) we generated during the quarter, and such NOLs were estimated at such time as unlikely to be realized in future periods. The increase in the valuation allowance was the primary factor reducing our income tax benefit (based on the U.S. statutory rate) to zero for the second quarter of 2021.
Six Months Ended SeptemberJune 30, 2017 (Successor)2022 Compared to NineSix Months Ended SeptemberJune 30, 2016(Predecessor)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) | | Six Months Ended June 30, | | Increase/(Decrease) |
| | For the Nine Months Ended September 30, 2017 | | | For the Nine Months Ended September 30, 2016 | | $ | | % | | 2022 | | 2021 | | $ | | % |
| Net revenues (in thousands): | | | | | | | | | Net revenues (in thousands): | | | | | | | |
| Oil sales | $ | 204,702 |
| | | $ | 56,975 |
| | $ | 147,727 |
| | 259 | % | Oil sales | $ | 612,358 | | | $ | 310,831 | | | $ | 301,527 | | | 97 | % |
| Natural gas sales | 33,226 |
| | | 5,717 |
| | 27,509 |
| | 481 | % | Natural gas sales | 107,048 | | | 62,466 | | | 44,582 | | | 71 | % |
| NGL sales | 25,844 |
| | | 3,097 |
| | 22,747 |
| | 734 | % | NGL sales | 100,525 | | | 51,671 | | | 48,854 | | | 95 | % |
| Total net revenues | $ | 263,772 |
| | | $ | 65,789 |
| | $ | 197,983 |
| | 301 | % | |
| Oil and gas sales | | Oil and gas sales | $ | 819,931 | | | $ | 424,968 | | | $ | 394,963 | | | 93 | % |
| | | | | | | | | | | | | | | | |
| Average sales prices: | | | | | | | | | Average sales prices: | |
| Oil (per Bbl) | $ | 45.76 |
| | | $ | 37.48 |
| | $ | 8.28 |
| | 22 | % | Oil (per Bbl) | $ | 97.42 | | | $ | 57.08 | | | $ | 40.34 | | | 71 | % |
| Effect of derivative settlements on average price (per Bbl) | 0.12 |
| | | 15.30 |
| | (15.18 | ) | | (99 | )% | Effect of derivative settlements on average price (per Bbl) | (15.03) | | | (11.12) | | | (3.91) | | | (35) | % |
| Oil net of hedging (per Bbl) | $ | 45.88 |
| | | $ | 52.78 |
| | $ | (6.90 | ) | | (13 | )% | Oil net of hedging (per Bbl) | $ | 82.39 | | | $ | 45.96 | | | $ | 36.43 | | | 79 | % |
| | | | | | | | | | | | | | | | |
| Average NYMEX price for oil (per Bbl) | $ | 49.44 |
| | | 41.43 |
| | 8.01 |
| | 19 | % | Average NYMEX price for oil (per Bbl) | $ | 101.37 | | | $ | 61.95 | | | $ | 39.42 | | | 64 | % |
| Oil differential from NYMEX | | Oil differential from NYMEX | (3.95) | | | (4.87) | | | 0.92 | | | 19 | % |
| | | | | | | | | | |
| Natural gas (per Mcf) | $ | 2.78 |
| | | $ | 2.24 |
| | $ | 0.54 |
| | 24 | % | Natural gas (per Mcf) | $ | 5.13 | | | $ | 3.13 | | | $ | 2.00 | | | 64 | % |
| Effect of derivative settlements on average price (per Mcf) | (0.02 | ) | | | — |
| | (0.02 | ) | | 100 | % | Effect of derivative settlements on average price (per Mcf) | (1.06) | | | 0.01 | | | (1.07) | | | (10,700) | % |
| Natural gas net of hedging (per Mcf) | $ | 2.76 |
| | | $ | 2.24 |
| | $ | 0.52 |
| | 23 | % | Natural gas net of hedging (per Mcf) | $ | 4.07 | | | $ | 3.14 | | | $ | 0.93 | | | 30 | % |
| | | | | | | | | | | | | | | | |
| Average NYMEX price for natural gas (per Mcf) | $ | 3.05 |
| | | 2.34 |
| | 0.71 |
| | 30 | % | Average NYMEX price for natural gas (per Mcf) | $ | 6.00 | | | $ | 3.15 | | | $ | 2.85 | | | 90 | % |
| Natural gas differential from NYMEX | | Natural gas differential from NYMEX | (0.87) | | | (0.02) | | | (0.85) | | | (4,250) | % |
| | | | | | | | | | |
| NGL (per Bbl) | $ | 23.67 |
| | | $ | 12.80 |
| | $ | 10.87 |
| | 85 | % | NGL (per Bbl) | $ | 46.74 | | | $ | 30.10 | | | $ | 16.64 | | | 55 | % |
| | | | | | | | | | |
| Net production: | | | | | | | | | Net production: | |
| Oil (MBbls) | 4,473 |
| | | 1,520 |
| | 2,953 |
| | 194 | % | Oil (MBbls) | 6,286 | | | 5,446 | | | 840 | | | 15 | % |
| Natural gas (MMcf) | 11,938 |
| | | 2,551 |
| | 9,387 |
| | 368 | % | Natural gas (MMcf) | 20,866 | | | 19,956 | | | 910 | | | 5 | % |
| NGL (MBbls) | 1,092 |
| | | 242 |
| | 850 |
| | 351 | % | NGL (MBbls) | 2,151 | | | 1,717 | | | 434 | | | 25 | % |
Total (MBoe) (1) | 7,554 |
| | | 2,187 |
| | 5,367 |
| | 245 | % | Total (MBoe)(1) | 11,914 | | | 10,488 | | | 1,426 | | | 14 | % |
| | | | | | | | | | | | | | | | |
| Average daily net production volume: | | | | | | | | | |
| Average daily net production: | | Average daily net production: | |
| Oil (Bbls/d) | 16,384 |
| | | 5,547 |
| | 10,837 |
| | 195 | % | Oil (Bbls/d) | 34,729 | | | 30,086 | | | 4,643 | | | 15 | % |
| Natural gas (Mcf/d) | 43,729 |
| | | 9,310 |
| | 34,419 |
| | 370 | % | Natural gas (Mcf/d) | 115,280 | | | 110,253 | | | 5,027 | | | 5 | % |
| NGL (Bbls/d) | 3,999 |
| | | 883 |
| | 3,116 |
| | 353 | % | |
| NGLs (Bbls/d) | | NGLs (Bbls/d) | 11,881 | | | 9,484 | | | 2,397 | | | 25 | % |
Total (Boe/d) (1) | 27,670 |
| | | 7,982 |
| | 19,688 |
| | 247 | % | Total (Boe/d)(1) | 65,824 | | | 57,945 | | | 7,879 | | | 14 | % |
| |
(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 ninesix months of 2017 (Successor)ended June 30, 2022 were $198.0$395.0 million, (or 301%)or 93%, higher than total net revenues for the ninesix months of 2016 (Predecessor). Our revenuesended June 30, 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 for the first half of 2022 compared to the same 2021 period by 71%, 64%, and 55%, respectively. The 71% increase in the average realized oil price was mainly the result of higher (64%) NYMEX crude prices between periods, as well as improved oil differentials ($0.92 per Bbl narrower). The average realized sales price of natural gas increased 64% due to higher (90%) average NYMEX gas prices between periods, partially offset by wider gas differentials ($0.85 per Mcf wider). The 55% increase in average realized NGL prices between periods was primarily attributable to higher Mont Belvieu spot prices for plant products for the first half of 2022 compared to the first half of 2021. The market prices for oil, natural gas and NGLs have all been impacted by global supply constraints for oil and gas throughout 2021 and 2022, as well as increasing demand worldwide as global economies emerge from COVID-19 era lockdowns and restrictions, as discussed in the market conditions section above.
Net production volumes for oil, natural gas, and NGLs increased 194%15%, 368%5%, and 351%25%, 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 603 MBbls of net oil production to our nine months ended September 30, 2017 results.Basin. Since the thirdsecond quarter of 2016,2021, we have placed 49 operated50 wells on production, in the Delaware Basin, which has added 2,8262,788 MBbls of net oil production to the first ninesix months ended June 30, 2022 as compared to 28 wells brought online since the second quarter of 2017. The increase in our operated well count is attributable2020 that added 1,214 MBbls of net oil production to the ramp up of our drilling program starting in the fourth quarter of 2016.six months ended June 30, 2021. These oil volume increases were partially offset by normal production declinesdecline across our existing wells. Our naturalNatural gas and NGLs are produced concurrently with our crude oil volumes, typically resulting in a high correlation between fluctuations in our oil quantities sold and our natural gas and NGL quantities sold. NaturalHowever, the main processor of our raw gas and NGL volumes were also impacted byoperated in partial ethane-recovery during 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 upfirst half of 41% natural gas and NGL volumes2022, as compared to 31%operating in full ethane-rejection during the same 2016 period.
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 when comparingbeing recovered from our wet gas stream during the nine months ended September 30, 2017 to the same 20162022 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 selectedsummarizes our operating expense dataexpenses for the periods indicated:
| | | | | | | | | | | | | | | | | | | | | | | |
| Six Months Ended June 30, | | Increase/(Decrease) |
| 2022 |
| 2021 | | Change | | % |
| Operating costs (in thousands): | | | | | | | |
| Lease operating expenses | $ | 57,634 | | | $ | 48,837 | | | $ | 8,797 | | | 18 | % |
| Severance and ad valorem taxes | 59,746 | | | 28,367 | | | 31,379 | | | 111 | % |
| Gathering, processing and transportation expenses | 47,647 | | | 40,119 | | | 7,528 | | | 19 | % |
| Operating cost metrics: | | | | | | | |
| Lease operating expenses (per Boe) | $ | 4.84 | | | $ | 4.66 | | | $ | 0.18 | | | 4 | % |
| Severance and ad valorem taxes (% of revenue) | 7.3 | % | | 6.7 | % | | 0.6 | % | | 9 | % |
| Gathering, processing and transportation expenses (per Boe) | $ | 4.00 | | | $ | 3.83 | | | $ | 0.17 | | | 4 | % |
|
| | | | | | | | | | | | | | | |
| | 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 ninesix months ended SeptemberJune 30, 2017 (Successor)2022 increased $16.6$8.8 million compared to the comparable 2016 period (Predecessor).six months ended June 30, 2021. Higher LOE for the first nine monthshalf of 20172022 was primarily related to (i) a $12.6$2.2 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,in electricity costs between periods due to electricity credits received during 2021 related Winter Storm Uri that were not similarly received in 2022; (ii) an increase in workover activity increased $4.0expense of $1.8 million between periods as a result ofperiods; and (iii) higher fixed and variable costs associated with our higher well count. We had 65count, which increased to 435 gross operated horizontal wells as of SeptemberJune 30, 2016 as compared to 1712022 from 409 gross operated horizontal wells as of SeptemberJune 30, 2017.2021. These increases were partially offset by lower water handling costs, which are associated with our higher level of recycling activity whereby produced water from our operated wells is recycled and then reused in our drilling and completion operations. This process results in significantly lower costs as compared to typical water disposal rates.
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$4.84 for the ninesix months ended SeptemberJune 30, 2017,2022, which represents a decreasean increase of $1.15$0.18 per Boe (or 24%4%) from the nine months ended September 30, 2016.comparable 2021 period. This decrease in rateincrease was mainly due to flush production from new wells we drilledprimarily driven by per Boe increases associated with (i) higher electricity expenses between periods (discussed above); (ii) higher workover expense; and completed over the past 12 months, which has the effect of reducing(iii) fixed and semi-variable costs, onsuch as monthly equipment rentals, repair work, labor, and wellhead chemical costs, that increase at a higher rate than increases in production. These per Boe basis.increases were partially offset by decreases in our water handling costs described above.
Severance and Ad Valorem Taxes. Severance and ad valorem taxes for the six months ended June 30, 2022 increased $31.4 million compared to the six months ended June 30, 2021. Severance taxes are primarily based on the market value of our production at the wellhead, andwhile ad valorem taxes are generally based on the valuationassessed taxable value of our proved developed 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)first half of 2022 increased $10.8$29.0 million (or 308%) compared to the nine 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 $2.4 million due to higher tax assessments on our oil and gas reserve values.
Severance and ad valorem taxes as a percentage of our revenue remained consistenttotal net revenues increased to 7.3% 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”)first half of 2022 as compared to 6.7% 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 20172021 period. This increase in rate was the result of a larger portion of our oil and gas volumes being produced in New Mexico, which levies higher severance tax rates than Texas, during the first half of 2022.
Gathering, Processing and Transportation Expenses. GP&T for the six months ended June 30, 2022 increased $7.5 million compared to the six months ended June 30, 2021. Similarly, GP&T on a per Boe basis increased from $3.83 for the first half of 2021 to $4.00 for the same 2022 period. These increases were mainly attributable to the change in our gas/oil ratio whereby a higher percentage of our total production was made up ofgas plant processing costs, whose variable fee portion is based on natural gas and NGL volumes during the nine months ended September 30, 2017, and thus a higher proportionprices, both 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 ratewhich increased only 12%substantially between periods from $6.56 to $7.32 for the nine months ended September 30, 2016 and 2017, respectively.as discussed above. This increase was primarily the resultpartially offset by a higher portion of a new firm transportation agreement we entered intoour 2022 oil and gas volumes being produced from our New Mexico wells, where our GP&T rates are currently lower than those 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).Texas.
Depreciation, Depletion and Amortization. The following table summarizes our DD&A for the periods indicated:
| | | | | | | | | | | |
| Six Months Ended June 30, |
| (in thousands, except per Boe data) | 2022 | | 2021 |
| Depreciation, depletion and amortization | $ | 153,126 | | | $ | 137,212 | |
| Depreciation, depletion and amortization per Boe | $ | 12.85 | | | $ | 13.08 | |
|
| | | | | | | | |
| | 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 incurred, acquisitions, impairments, as well as changes in proved reserves ordeveloped and proved developedundeveloped 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 2017per Boe was the increase in overall production volumes between periods, which resulted in $149.5 million of incremental DD&A expense being incurred during$12.85 for the first nine monthshalf of 2017. This increase was largely offset, however, by a $107.6 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 $13.61 for the nine months ended September 30, 2017 was 51% lower than the rate of $27.86$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 our proved reservesthe Company continuing to complete wells with low finding and development costs and high quantities of associated 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 thirdsecond 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, 2016.2021.
General and Administrative Expenses. The following table summarizes our G&A expenses for the periods indicated:
| | | | Successor | | | Predecessor | | Six Months Ended June 30, |
| (in thousands) | For the Nine Months Ended September 30, 2017 | | | For the Nine Months Ended September 30, 2016 | (in thousands) | 2022 |
| 2021 |
| Stock-based compensation expense | $ | 8,288 |
| | | $ | — |
| |
| Cash general and administrative expenses | 27,729 |
| | | 9,735 |
| Cash general and administrative expenses | $ | 24,203 | | | $ | 20,758 | |
| Stock-based compensation expense - equity awards | | Stock-based compensation expense - equity awards | 11,220 | | | 8,637 | |
| Stock-based compensation expense - liability awards | | Stock-based compensation expense - liability awards | 5,127 | | | 24,668 | |
| General and administrative expenses | $ | 36,017 |
| | | $ | 9,735 |
| General and administrative expenses | $ | 40,550 | | | $ | 54,063 | |
G&A expenses for the ninesix months ended SeptemberJune 30, 2017 (Successor) increased $26.32022 were $40.6 million overcompared to $54.1 million for the same 2016 period (Predecessor).six months ended June 30, 2021. Lower G&A in the first half of 2022 was the result of a $17.0 million decrease in total stock-based compensation expense between periods. This increasedecrease was primarily related to performance stock units granted in 2020 that are recorded at their respective fair value each balance sheet date, and such fair value decreased between periods. This decrease was slightly offset by higher cash G&A which increased $3.4 million period over period due to $14.7higher payroll and other personnel cost increases.
Merger and integration expense. Merger and integration expense for the six months ended June 30, 2022 was $5.7 million in higher employee salaries and relatedincludes costs between periods, $8.3incurred for the pending Merger consisting primarily of legal and advisory fees. See Note 2—Business Combination for further details regarding the pending Merger.
Impairment and Abandonment Expense. During the six months ended June 30, 2022, impairment and abandonment expense was $3.1 million of stock-based compensation incurredas compared to $18.4 million during the ninesix months ended SeptemberJune 30, 2017 versus none in2021. Both periods consist 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: | | | | | | | | | | | |
| Six Months Ended June 30, |
| (in thousands) | 2022 |
| 2021 |
| Geological and geophysical costs | $ | 3,237 | | | $ | 1,786 | |
| Stock-based compensation - equity awards | 982 | | | 429 | |
| Stock-based compensation - liability awards | — | | | 406 | |
| Other expenses | 42 | | | 238 | |
| Exploration and other expenses | $ | 4,261 | | | $ | 2,859 | |
Exploration and other expenses were $4.3 million for the six months ended June 30, 2022 compared to $2.9 million for the same prior year period. Exploration and other expenses mainly consist of topographical studies, G&G projects, salaries and expenses of G&G personnel and includes other operating costs. The period and $2.9 millionover period increase was primarily related to higher G&G personnel costs in increased professional fees. Employee-related costs were substantially higher during the nine months ended September 30, 2017 due to the numbersecond half 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.2022.
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 expensesexpense for the periods indicated: | | | | | | | | | | | |
| Six Months Ended June 30, |
| (in thousands) | 2022 | | 2021 |
| Credit facility | $ | 1,649 | | | $ | 6,077 | |
| 8.00% Senior Secured Notes due 2025 | — | | | 2,908 | |
| 5.375% Senior Notes due 2026 | 7,778 | | | 7,778 | |
| 6.875% Senior Notes due 2027 | 12,250 | | | 12,250 | |
| 3.25% Convertible Senior Notes due 2028 | 2,762 | | | 1,553 | |
| Amortization of debt issuance costs and debt discount | 4,226 | | | 2,887 | |
| Interest capitalized | (1,185) | | | (786) | |
| Total | $ | 27,480 | | | $ | 32,667 | |
|
| | | | | | | | |
| | 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 |
|
ForInterest expense was $5.2 million lower for the ninesix months ended SeptemberJune 30, 2017 (Successor), we incurred $2.62022 compared to the same 2021 period mainly due to (i) $4.4 million in lower interest incurred on our Credit Agreement due to lower borrowings outstanding during the 2022 period, and (ii) $2.9 million in decreased interest expense on our Senior Secured Notes due 2025 that were redeemed in April of 2021. These decreases were partially offset by (i) additional debt issuance costs amortized during the six months ended June 30, 2022 related to CRP’s credit facilityfees incurred for an incremental commitment letter we entered into in connection with the Merger, and (ii) interest on our Convertible Senior Notes that was incurred in 2022 but only partially during the 2021 period due to their issuance in March 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. 2021.
Our weighted average debtborrowings outstanding for the nine months ended September 30, 2017 was $46.1under our Credit Agreement were $16.5 million versus $99.5$310.2 million for the same 2016 period.first half of 2022 and 2021, respectively. Our Credit Agreement’s weighted average effective interest rate was 3.72% during2.9% and 3.4% for the ninesix months ended SeptemberJune 30, 2017 compared2022 and 2021, respectively.
Gain (loss) on extinguishment of debt. During the six months ended June 30, 2021, we redeemed at par all of our $127.1 million aggregate principal amount of Senior Secured Notes outstanding. In connection with this redemption, we recorded a loss on debt extinguishment of $22.2 million related to 2.67% for the comparable 2016 period.write-off of all unamortized debt issuance costs and debt discounts associated with these notes.
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 prices.each of our hedge contracts outstanding and ii)(ii) monthly cash settlements of our hedgedon any closed out hedge positions during the period.
The following table presents gains and losses for derivative positions. For the nine months ended September 30, 2017 (Successor), we recognized non-cash mark-to-market derivative gains of $5.1 million compared to non-cash mark-to-market losses of $20.8 millioninstruments for the same 2016 period (Predecessor)periods indicated:
| | | | | | | | | | | | | | | | | |
| Six Months Ended June 30, | | | | | | |
| (in thousands) | 2022 | | 2021 | | | | | | |
| Realized cash settlement gains (losses) | $ | (116,526) | | | $ | (60,399) | | | | | | | |
| Non-cash mark-to-market derivative gain (loss) | (47,131) | | | (45,759) | | | | | | | |
| Total | $ | (163,657) | | | $ | (106,158) | | | | | | | |
Income Tax (Expense) Benefit. Cash derivative settlements amounted to $0.3 millionThe following table summarizes our pre-tax income (loss) and $16.6 million in gainsincome tax (expense) benefit for the nine months of 2017 and 2016, respectively.periods indicated:
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 | | | | | | | | | | | |
| Six Months Ended June 30, |
| (in thousands) | 2022 | | 2021 |
| Income (loss) before income taxes | $ | 255,891 | | | $ | (59,700) | |
| Income tax (expense) benefit | (48,263) | | | — | |
Our provisions for income taxes for the nine months ended September 30, 2017 differedfirst half of 2022 and 2021 differs from the amountamounts that would be provided by applying the blended statutory U.S. federal state, and local income tax rate of 36.1%21% to pre-tax book income (loss) primarily becausedue to (i) state income taxes; (ii) permanent differences; and (iii) any changes during the Company released $5.1 million of itsperiod in our deferred tax asset valuation allowance inallowance.
For the first halfsix months ended June 30, 2022 we generated pre-tax net income of 2017, such that$255.9 million and recorded income tax expense of $17.3$48.3 million. The primary factor decreasing our income tax expense below the U.S. statutory rate was the partial release of our deferred tax valuation allowance due to the generation of net income in the current year.
For the six months ended June 30, 2021, we recognized deferred tax asset valuation allowances of $20.0 million against NOLs we generated during the period, and such NOLs were estimated at such time as unlikely to be realized in future periods. The increase in our valuation allowance was the primary factor reducing our income tax benefit (based on the U.S. statutory rate) to zero for the ninefirst six months ended September 30, 2017 was partially offset by the tax benefit associated with the portion of the valuation allowance released resulting in an effective tax rate2021.
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 ninesix months ended SeptemberJune 30, 2017:2022:
| | | | | |
| (in millions) | Six Months Ended June 30, 2022 |
| Drilling, completion and facilities | $ | 248.4 | |
| Infrastructure, land and other | 6.9 | |
| |
| Total capital expenditures incurred | $ | 255.3 | |
|
| | | |
| (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 half of 2022. We expect our total capex budget for 2017 is $535.02022 on a stand alone basis 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 six months ended June 30, 2022 entirely from cash flows from operations, and borrowings. The drillingwe expect to fund the remainder of our stand alone 2022 capex budget entirely from cash flows from operations as well, given our anticipated level of oil and completion (“D&C”)gas production, current commodity prices and our commodity hedge positions in place. We generated free cash flow during the first half of 2022 such that we were able to pay down all of our borrowings under our Credit Agreement during the period.
In May 2022, we announced the pending Merger with Colgate that is expected close in the third quarter of 2022. If the Merger closes as expected, our 2022 operational plans and sources and use of capital, among others things, as a combined entity will change, and such changes are expected to include (i) the Company assuming $1.0 billion of Colgate’s senior notes and Colgate’s credit facility borrowings outstanding at closing, which will be refinanced under CRP’s Credit Agreement, (ii) potential borrowings under CRP’s Credit Agreement to fund some portion of the $525 million in cash Merger consideration due at closing, and (iii) the funding of additional transaction costs yet to be incurred related to the Merger.
In February 2022, our 2017 capital budget represents a significant increase overBoard of Directors authorized the $97.7Repurchase 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 from operations. Such repurchases would be made at terms and prices determined by us based upon prevailing market conditions, applicable legal requirements, available liquidity, compliance with our debt and other agreements and other factors. Due to restrictions related to the Merger, we have been unable to make or initiate any share repurchases under the Repurchase Program since the announcement and therefore, we will not be generatedable to begin repurchasing our shares until the pending Merger closes or is otherwise terminated. In addition, we may, from (i) new wells we drilled and completedtime to time, seek to retire or purchase our outstanding senior notes through cash purchases and/or exchanges for debt in latter 2016 and plan to drill 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.open-market purchases, privately negotiated transactions or otherwise.
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:
| | | | | | | | | | | |
| Six Months Ended June 30, |
| (in thousands) | 2022 | | 2021 |
| Net cash provided by operating activities | $ | 455,099 | | | $ | 179,625 | |
| Net cash used in investing activities | (228,603) | | | (127,076) | |
| Net cash used in financing activities | (34,784) | | | (53,644) | |
|
| | | | | | | | |
| | 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 ninesix months ended SeptemberJune 30, 2017,2022, we generated $137.2$455.1 million of cash provided byfrom operating activities, an increase of $85.6$275.5 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 ninesix months ended SeptemberJune 30, 2017.2022. 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 six months ended SeptemberJune 30, 20172022 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 ninesix months ended SeptemberJune 30, 2017,2022, 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$224.0 million of drilling and development cash expenditures while $333.5and repay net borrowings of $25.0 million inunder our Credit Agreement.
During the six months ended June 30, 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 $126.7 million of drilling and development cash on hand, $35.0 million inexpenditures, repay net borrowings of $75.0 million under our credit facility, redeem $127.1 million of our 2025 senior secured notes outstanding 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 SeptemberJune 30, 2017,2022, 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 itCRP 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 SeptemberJune 30, 20172022 and through the filing of this report.Quarterly Report.
Off-Balance Sheet ArrangementsOn July 15, 2022, CRP and the Company entered into the Amendment to our Credit Agreement. The Amendment, among other things, waives compliance with certain restrictive covenants and provides the lenders’ consent to a planned Pre-Merger Reorganization (as defined within the Amendment) in order to enable the Merger. In addition, the Amendment increases the elected commitments under the Credit Agreement to $1.5 billion from $750 million and the borrowing base to $2.5 billion from $1.15 billion. The Amendment is subject to and effective as of the closing date of the Merger and will be terminated if the Merger has not occurred prior to November 30, 2022.
AsFor further information on the Credit Agreement, refer to Note 4—Long-Term Debt under Part I, Item I of Septemberthis Quarterly Report.
Convertible Senior Notes
On March 19, 2021, CRP issued $150.0 million 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 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 4—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 June 30, 2022 and through the filing of this Quarterly Report.
For further information on our Convertible Senior Notes and Senior Unsecured Notes, refer to Note 4—Long-Term Debt under Part I, Item I of this Quarterly Report.
Contractual Obligations
Our contractual obligations include operating and transportation agreements, drilling rig contracts, office and equipment leases, asset retirement obligations, long-term debt obligations and cash interest expense on long-term debt obligations, which we 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 12—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 ninesix months ended SeptemberJune 30, 20172022 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 June 30, 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 half of 2022, our oil and gas sales for the six months ended June 30, 2022 would have moved up or down $61.2 million for each 10% change in the future.oil prices per Bbl, $10.1 million for each 10% change in NGL prices per Bbl, and $10.7 million for each 10% change in natural gas prices per Mcf.
Due to this volatility, we have historically used, and we expectmay elect to continue to opportunisticallyselectively use, commodity derivative instruments such(such as collars, swaps collars and basis swaps,swaps) to mitigate price risk associated with a portion of our anticipated production. Our derivative instruments allow us to reduce, but not eliminate, the potential effects of the variability in cash flowflows that can emanate from operations due to fluctuations in oil and natural gas prices, and thereby provide increased certainty of cash flows for our drilling program and debt service requirements. These instruments provide only partial price protection against declines in oil and natural gas prices, and maybut alternatively they partially limit our potential gains from future increases in prices. CRP’s credit agreementOur Credit Agreement limits itsour ability to enter into commodity hedges covering greater than 80%85% of itsour reasonably anticipated projected production volume.from proved properties.
The following table below summarizes the approximate volumes and average contract pricesterms of swapthe derivative contracts the Companywe had in place as of SeptemberJune 30, 2017:2022 and additional contracts entered into through July 31, 2022. Refer to Note 7—Derivative Instruments in Item 1 of Part I of this Quarterly Report for open derivative positions as of June 30, 2022. | | | | | | | | | | | | | | | | | | | | | | | |
| Period | | Volume (Bbls) | | Volume
(Bbls/d) | | Wtd. Avg. Crude Price ($/Bbl)(1) |
| Crude oil swaps | 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 | July 2022 - September 2022 | | 460,000 | | | 5,000 | | | $78.00 | - | $107.13 |
| October 2022 - December 2022 | | 644,000 | | | 7,000 | | | 80.00 | - | 104.17 |
| January 2023 - March 2023 | | 810,000 | | | 9,000 | | | 75.56 | - | 91.15 |
| April 2023 - June 2023 | | 819,000 | | | 9,000 | | | 75.56 | - | 91.15 |
| July 2023 - September 2023 | | 644,000 | | | 7,000 | | | 76.43 | - | 92.70 |
| October 2023 - December 2023 | | 644,000 | | | 7,000 | | | 76.43 | - | 92.70 |
| | | | | | | | | |
| | | | | | | | | |
| | | | | | | | | |
|
| | | | | | |
| Description & Production Period | Volume (Bbl) | | Weighted Average Fixed Price/Differential ($/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 basis differential swaps | 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 | July 2022 - September 2022 | | 920,000 | | | 10,000 | | | $0.71 |
| October 2022 - December 2022 | | 920,000 | | | 10,000 | | | 0.71 |
| | | | | | | |
(1) These crude oil swap transactions are settled based on the NYMEX WTI index price on each trading day within the specified monthly settlement period versus the contractual swap price for the volumes stipulated.
(2) These crude oil collars are settled based on the NYMEX WTI index price, on each trading day within the specified monthly settlement period versus the contractual floor and ceiling prices for the volumes stipulated.
(3) These crude oil basis swap transactions are settled based on the difference between the arithmetic average of ARGUS MIDLAND WTI and ARGUS WTI CUSHING indices, during each applicable monthly settlement period.
(4) These crude oil roll swap transactions are settled based on the difference between the arithmetic average of NYMEX WTI calendar month prices and the physical crude oil delivery month price.
| | | | | | | | | | | | | | | | | | | | | | | |
| Period | | Volume (MMBtu) | | Volume (MMBtu/d) | | Wtd. Avg. Gas Price ($/MMBtu)(1) |
| Natural gas swaps | 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 | 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 | July 2022 - September 2022 | | 1,840,000 | | | 20,000 | | | $3.50 | - | $3.97 |
| October 2022 - December 2022 | | 2,450,000 | | 26,630 | | | 3.87 | - | 5.06 |
| January 2023 - March 2023 | | 4,950,000 | | 55,000 | | | 4.09 | - | 7.47 |
| April 2023 - June 2023 | | 4,095,000 | | 45,000 | | | 3.72 | - | 7.32 |
| July 2023 - September 2023 | | 4,140,000 | | 45,000 | | | 3.72 | - | 7.32 |
| October 2023 - December 2023 | | 4,140,000 | | 45,000 | | | 3.76 | - | 7.69 |
| January 2024 - March 2024 | | 1,820,000 | | 20,000 | | | 3.25 | - | 5.31 |
| | | | | | | | | |
| |
(1)
| The oil swap contracts are settled based on the month’s average daily NYMEX price of West Texas Intermediate Light Sweet Crude. The oil basis swap contracts are settled based on the difference between the arithmetic average of WTI MIDLAND ARGUS and WTI ARGUS during the relevant calculation period. |
(1) These natural gas swap contracts are settled based on the NYMEX Henry Hub price on each trading day within the specified monthly settlement period versus the contractual swap price for the volumes stipulated.
(2) These natural gas basis swap contracts are settled based on the difference between the Inside FERC’s West Texas WAHA price and the NYMEX price of natural gas, during each applicable monthly settlement period.
(3) These natural gas collars are settled based on the NYMEX Henry Hub price on each trading day within the specified monthly settlement period versus the contractual floor and ceiling prices for the volumes stipulated.
|
| | | | | | |
| Description & Production Period | Volume (MMBtu) | | Weighted Average Fixed Price/Differential ($/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 | ) |
Changes in the fair value of derivative contracts from December 31, 2021 to June 30, 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 | | 116,526 | |
Cash and non-cash mark-to-market losses on commodity hedge contracts(1) | The natural | (163,656) | |
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.June 30, 2022 | | $ | (82,040) | |
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 SeptemberJune 30, 20172022 would cause a $1.1$48.1 million increase or $47.1 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 SeptemberJune 30, 20172022 would cause a $0.1$7.2 million increase or 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 June 30, 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 long-term debt balance of $801.8 million consists of our senior notes, which have fixed interest rates; therefore, this balance is not affected by interest rate movements. For additional information regarding our debt instruments, see Note 4—Long-Term Debt, in Item 1 of Part I of this Quarterly Report.
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 SeptemberJune 30, 2017.2022. 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 SeptemberJune 30, 20172022 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 SeptemberJune 30, 20172022 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 12—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.as well as additional risk factors set forth below. 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. ThereOther than with respect to the additional risk factors below, there have been no material changes in our risk factors from those described in our 20162021 Annual Report or our other SEC filings.
Risks Relating to the Transactions
The Transactions are subject to closing conditions and may not be completed, the Business Combination Agreement may be terminated in accordance with its terms, and we may be required to pay a termination fee upon termination.
On May 19, 2022, we entered into a Business Combination Agreement (the “Business Combination Agreement”) with CRP, Colgate Energy Partners III, LLC (“Colgate”), and, solely for purposes of the specified provisions therein, Colgate Energy Partners III MidCo, LLC (the “Colgate Unitholder”), pursuant to which, CRP will merge with and into Colgate (the “Merger”), with CRP surviving the Merger (the “Surviving Company”) and continuing as a subsidiary of the Company.
The transactions contemplated by the Business Combination Agreement (the “Transactions”) are subject to customary closing conditions that must be satisfied or waived prior to the completion of the Transactions, including the expiration of the waiting period under the Hart-Scott-Rodino Antitrust Improvements Act of 1976, as amended, and the rules promulgated thereunder (the “HSR Act”), no agreement shall be in effect between Colgate, Centennial or any of their respective subsidiaries, on the one hand, and the Antitrust Division of the Department of Justice (the “Antitrust Division”) or the U.S. Federal Trade Commission (the “FTC”), on the other hand, not to consummate the Transactions, and approval by our shareholders of the issuance of shares of Centennial common stock to the Colgate Unitholder (the “Stock Issuance Proposal”) and the approval and adoption of a Fourth Amended and Restated Certificate of Incorporation of Centennial Resource Development, Inc. (the “A&R Charter Proposal”). Many of the closing conditions are not within our control. While the waiting period under the HSR Act expired without objections or comments on July 5, 2022, no assurance can be given that no agreement will be in effect between Colgate, Centennial or any of their respective subsidiaries, on the one hand, and the Antitrust Division or FTC, on the other hand, not to consummate the Transactions and clearances and shareholder approvals will be obtained or that the required conditions to closing will be satisfied in a timely manner or at all. Any delay in completing the Transactions could cause the combined company not to realize, or to be delayed in realizing, some or all of the benefits that we expect to achieve if the Transactions are successfully completed within its expected time frame.
Additionally, either party may terminate the Business Combination Agreement under certain circumstances, including, among other reasons, if the Transactions are not completed by February 19, 2023 (subject to an automatic extension of such date
to May 19, 2023 in certain circumstances if additional time is needed to satisfy regulatory conditions). In addition, if the Business Combination Agreement is terminated under specified circumstances, we may be obligated to pay a termination fee of $72.0 million or to reimburse Colgate for certain of its transaction expenses in an amount of up to $20.0 million.
Moreover, if the Transactions are not completed for any reason, an agreement is in effect between Colgate, Centennial or any of their respective subsidiaries, on the one hand, and the Antitrust Division or FTC, on the other hand, not to consummate the Transactions or shareholder approval of the Stock Issuance Proposal and the A&R Charter Proposal are not obtained, our ongoing businesses may be adversely affected and, without realizing any of the expected benefits of having completed the Transactions, we would be subject to a number of risks, including the following:
•we may experience negative reactions from the financial markets, including negative impacts on our stock price;
•we may experience negative reactions from our customers, suppliers, distributors and employees;
•we will be required to pay our costs relating to the Transactions, such as financial advisory, legal, financing and accounting costs and associated fees and expenses, whether or not the Transactions are completed;
•the market price of our Class A common stock (“Common Stock”) could decline to the extent that the current market price reflects a market assumption that the Transactions will not be completed;
•the Business Combination Agreement places certain restrictions on the conduct of our business prior to completion of the Transactions and such restrictions, the waiver of which are subject to the consent of Colgate, may prevent us from taking actions during the pendency of the Transactions that would be beneficial; and
•matters relating to the Transactions (including integration planning) will require substantial commitments of time and resources by management, which could otherwise have been devoted to day-to-day operations or to other opportunities that may have been beneficial to us as an independent company.
The consideration payable under the Business Combination Agreement is fixed and will not be adjusted based on our performance.
Under the Business Combination Agreement, the total consideration payable by us consists of (i) 269,300,000 shares of Class C Common Stock, (ii) 269,300,000 additional units in the Surviving Company, (iii) $525 million in cash, subject to adjustments for certain Colgate title and environmental defect considerations set forth in the Business Combination Agreement. The purchase price will not be adjusted for changes in the market price of our Common Stock or the economic performance of Centennial or Colgate. If the market price of our Common Stock increases or the economic performance of Colgate relative to us declines (or the economic performance of Colgate relative to us improves), the consideration will not be adjusted to account for any such changes or any effective increase or decrease in the value of the consideration issued or paid to the Colgate Unitholder under the Business Combination Agreement.
We will be subject to business uncertainties and contractual restrictions, including the risk of litigation, while the Transactions are pending that may cause disruption and may make it more difficult to maintain relationships with employees, suppliers or customers.
Uncertainty about the effect of the Transactions on employees, suppliers and customers may have an adverse effect on Centennial and/or Colgate, which uncertainties may impair our or Colgate’s ability to attract, retain and motivate key personnel until the Transactions are completed and for a period of time thereafter, and could cause customers, suppliers and others that deal with Centennial or Colgate to seek to change existing business relationships with either of us.
Employee retention and recruitment may be challenging before the completion of the Transactions, as employees and prospective employees may experience uncertainty about their future roles following the Transactions. Key employees may depart or prospective key employees may fail to accept employment with us or Colgate because of issues relating to the uncertainty and difficulty of integration or a desire not to remain with the combined company following the Transactions, any of which could have a material adverse effect on our business, financial condition and results of operations.
The pursuit of the Transactions and the preparation for the integration may place a significant burden on management and internal resources. The diversion of management’s attention away from day-to-day business concerns and any difficulties encountered in the transition and integration process could have a material adverse effect on our business, financial condition and results of operations.
Until the completion of the Transactions or the termination of the Business Combination Agreement in accordance with its terms, we are prohibited from entering into certain transactions and taking certain actions that might otherwise be beneficial to us and our shareholders.
During the period between the date of the Business Combination Agreement and completion of the Transactions which, under the Business Combination Agreement, could take until February 19, 2023 (or until May 19, 2023 upon the automatic extension of such date in certain circumstances if additional time is needed to satisfy regulatory conditions), the Business Combination Agreement restricts us from taking specified actions or from pursuing what might otherwise be attractive business opportunities or making other changes to our business, in each case without the consent of Colgate. These restrictions may prevent us from taking actions during the pendency of the Transactions that would have been beneficial. Adverse effects arising from these restrictions during the pendency of the Transactions could be exacerbated by any delays in consummation of the Transactions or termination of the Business Combination Agreement.
The Business Combination Agreement limits our ability to pursue alternatives to the Transactions and may discourage a potential competing acquirer of Centennial, including the payment by Centennial of a termination fee.
The Business Combination Agreement contains provisions that, subject to limited exceptions, restrict our ability to (i) directly or indirectly initiate or solicit, or encourage or facilitate any inquiry or the making or submission of any proposal that constitutes, or would reasonably be expected to lead to, a Parent Acquisition Proposal (as defined in the Business Combination Agreement), (ii) other than clarifying terms of the Parent Acquisition Proposal so that Parent may inform itself about such Parent Acquisition Proposal or to inform a third party or its representatives of the restrictions imposed in accordance with the applicable terms of the Business Combination Agreement, participate or engage in discussions or negotiations with, or disclose any information or data related to Centennial or its subsidiaries or afford access to the properties, books or records of Centennial or its subsidiaries to any person that has made a Parent Acquisition Proposal or to any person in contemplation of making a Parent Acquisition Proposal, or (iii) accept a Parent Acquisition Proposal or enter into any agreement, including any letter of intent, memorandum of understanding, agreement in principal, merger agreement, acquisition agreement, option agreement, joint venture agreement, partnership agreement or other similar agreement, arrangement or understanding, (A) constituting or related to, or that is intended to or would reasonably be expected to lead to, any Parent Acquisition Proposal (other than a confidentiality agreement as provided in the Business Combination Agreement) or (B) requiring, intending to cause, or which could reasonably be expected to cause Centennial to abandon, terminate or fail to consummate the Transactions. In addition, before the Board withdraws, qualifies or modifies its recommendation of the proposed Transactions or terminates the Business Combination Agreement to enter into a definitive agreement with respect to a competing transaction, Colgate generally has an opportunity to offer to modify the terms of the proposed Transactions or Business Combination Agreement. In some circumstances, upon termination of the Business Combination Agreement, we will be required to pay Colgate a termination fee equal to $72.0 million.
These provisions could discourage a potential third-party acquirer that might have an interest in acquiring all or a significant portion of us from considering or proposing that acquisition, even if it were prepared to pay above market value, or might otherwise result in a potential third-party acquirer proposing to pay a lower price to Centennial shareholders than it might otherwise have proposed to pay because of the added expense of the termination fee that may become payable in certain circumstances.
If the Business Combination Agreement is terminated and we decide to seek another merger transaction, we may not be able to negotiate or consummate a transaction with another party on terms comparable to, or better than, the terms of the Business Combination Agreement.
The Transactions will involve substantial costs.
We have incurred and expect to incur non-recurring costs associated with the Transactions and combining the operations of the two companies, as well as transaction fees and other costs related to the Transactions. These costs and expenses include fees paid to legal, financial and accounting advisors, regulatory and public relations advisors, filing fees, printing costs and other costs and expenses. A significant portion of these transaction costs is contingent upon the Closing occurring, although some have been and will be incurred regardless of whether the Transactions are consummated.
In addition, the combined company will also incur significant restructuring and integration costs in connection with the integration of Centennial and Colgate and the execution of our business plan, including costs relating to formulating and implementing integration plans and eliminating duplicative costs, as well as potential employment-related costs. The costs related to restructuring will be expensed as a cost of the ongoing results of operations of either us or the combined company. There are processes, policies, procedures, operations, technologies and systems that must be integrated in connection with the Transactions and the integration of Colgate’s business. While we have assumed a certain level of expenses would be incurred to integrate Centennial and Colgate and achieve synergies and efficiencies and we continue to assess the magnitude of these costs, many of these expenses are, by their nature, difficult to estimate accurately and there are many factors beyond our control that could affect the total amount or timing of these costs. Although we expect that the elimination of duplicative costs, as well as the realization of
strategic benefits, additional income, synergies and other efficiencies should allow the combined company to offset integration-related costs over time, this net benefit may not be achieved in the near term, or at all.
Securities class action and derivative lawsuits may be filed against us, or against our directors, challenging the Transactions, and an adverse ruling in any such lawsuit may prevent the Transactions from becoming effective or from becoming effective within the expected time frame.
Securities class action lawsuits and derivative lawsuits are often brought against public companies that have entered into acquisition, merger or other business combination agreements. Transactions like the Transactions are frequently subject to litigation or other legal proceedings, including actions alleging that our Board breached their fiduciary duties to our shareholders by entering into the Business Combination Agreement. We cannot provide assurance that such litigation or other legal proceedings will not be brought. If litigation or other legal proceedings are in fact brought against us, or against our Board, we will defend against it, but might not be successful in doing so. An adverse outcome in such matters, as well as the costs and efforts of a defense even if successful, could have a material adverse effect on the business, results of operation or financial position of us or the combined company, including through the possible diversion of company resources or distraction of key personnel.
Lawsuits that may be brought against us, Colgate or our or its directors could also seek, among other things, injunctive relief or other equitable relief, including a request to enjoin us from consummating the Transactions. One of the conditions to the Closing are that no order, award or judgment by any court or other tribunal of competent jurisdiction has been entered and continues to be in effect and no law has been adopted or is effective, in either case, that prohibits or makes illegal the Closing. Consequently, if a plaintiff is successful in obtaining an order, award or judgment prohibiting completion of the Transactions, that order, award or judgment may delay or prevent the Transactions from being completed within the expected time frame or at all, which may adversely affect our business, financial position and results of operations.
We will incur additional indebtedness in connection with the Transactions, and the combined company’s debt may impose certain financial and operational limitations.
In addition to our existing indebtedness under our credit facilities and indentures, we plan to (i) incur additional debt under CRP’s revolving credit facility in order to fund the approximately $525 million of Cash Consideration and (ii) assume $1.0 billion of Colgate’s senior notes and Colgate’s credit facility borrowings outstanding at closing as part of the Transactions. The amount of debt to be borrowed under CRP’s revolving credit facility as part of the Transactions will be dependent upon the amount of our cash and cash equivalents as of the closing date of the Merger.
While we expect to generate material free cash flow prior to the Closing to offset a portion of this debt, the combined company’s level of indebtedness following completion of the Transactions could have important consequences. For example, it could:
•increase our vulnerability to general adverse economic and industry conditions;
•impair our ability to obtain additional debt or equity financing in the future for working capital, capital expenditures development of estimated proved undeveloped reserves (‘PUDs”), development and acquisition projects, acquisitions or general corporate or other purposes;
•require us to dedicate a material portion of our cash flows to the payment of principal and interest on our indebtedness, thereby reducing the availability of our cash flows to fund working capital needs, capital expenditures, development of estimated PUDs, development and acquisition projects, acquisitions and other general corporate purposes;
•expose us to variable interest rate risk to the extent we make borrowings under CRP’s revolving credit facility;
•limit our flexibility in planning for, or reacting to, changes in our business and the industry in which we operate;
•place us at a disadvantage compared to our competitors that have less indebtedness; and
•limit our ability to adjust to changing market conditions.
Any of these risks could materially impact our ability to fund our operations or limit our ability to expand the combined business, which could have a material adverse effect on the combined business, financial condition and results of operations.
Combining the businesses of Centennial and Colgate may be more difficult, costly or time-consuming than expected and the combined company may fail to realize the anticipated synergies and other benefits of the Transactions, which may adversely affect the combined company’s business results and negatively affect the value of our Common Stock following the consummation of the Transactions.
Centennial and Colgate have operated and, until the completion of the Transactions will continue to operate, independently. The success of the Transactions will depend on, among other things, the ability of Centennial and Colgate to combine their businesses in a manner that facilitates growth opportunities and realizes expected cost savings. We have entered into the Business
Combination Agreement because we believe that the transactions contemplated by the Business Combination Agreement are fair to and in the best interests of our shareholders and that combining the businesses of Centennial and Colgate will produce benefits as well as cost savings and other cost and capital expenditure synergies.
Following the Closing, Centennial and Colgate must successfully combine their respective businesses in a manner that permits these benefits to be realized. For example, the following issues, among others, must be addressed in integrating the operations of the two companies in order to realize the anticipated benefits of the Transactions:
•combining the companies’ operations and corporate functions;
•combining the businesses of Centennial and Colgate and meeting the capital requirements of the combined company, in a manner that permits the combined company to achieve any cost savings or other synergies anticipated to result from the Transactions, the failure of which would result in the anticipated benefits of the Transactions not being realized in the time frame currently anticipated or at all;
•integrating personnel from the two companies;
•integrating and unifying our reserves and the development of our new PUDs;
•identifying and eliminating underperforming or uncertain wells;
•harmonizing the companies’ operating practices, employee development and compensation programs, internal controls and other policies, procedures and processes;
•maintaining existing agreements with customers, suppliers, distributors and vendors, avoiding delays in entering into new agreements with prospective customers, suppliers, distributors and vendors, and leveraging relationships with such third parties for the benefit of the combined company;
•addressing possible differences in business backgrounds, corporate cultures and management philosophies;
•consolidating the companies’ administrative and information technology infrastructure;
•coordinating distribution and marketing efforts;
•managing the movement of certain positions to the new proposed headquarters in Midland, Texas; and
•effecting actions that may be required in connection with obtaining regulatory or other governmental approvals.
It is possible that the integration process could result in the loss of key Centennial or Colgate employees, the loss of customers, the disruption of either company’s or both companies’ ongoing businesses, inconsistencies in standards, controls, procedures and policies, unexpected integration issues, higher than expected integration costs and an overall post-completion integration process that takes longer than originally anticipated. In addition, the actual integration may result in additional and unforeseen expenses. If the combined company is not able to adequately address integration challenges, we may be unable to successfully integrate operations and the anticipated benefits of the integration plan may not be realized.
In addition, the combined company must achieve the anticipated growth and cost savings without adversely affecting current revenues and investments in future growth. If the combined company is not able to successfully achieve these objectives, the anticipated synergies and other benefits of the Transactions may not be realized fully, or at all, or may take longer to realize than expected. Additionally, we may inherit from Colgate legal, regulatory, and other risks that occurred prior to the Transactions, whether known or unknown to us, which may be material to the combined company. Actual growth, cost and capital expenditure synergies and other cost savings, if achieved, may be lower than what we expect and may take longer to achieve than anticipated. Moreover, at times the attention of the combined company’s management and resources may be focused on the integration of the businesses of the two companies and diverted from day-to-day business operations or other opportunities that may have been beneficial to such company, which may disrupt the combined company’s ongoing business.
An inability to realize the full extent of the anticipated benefits of the Transactions, as well as any delays encountered in the integration process, could have an adverse effect upon the revenues, level of expenses and operating results of the combined company, which may adversely affect the value of our Common Stock following the consummation of the Transactions. Moreover, if the combined company is unable to realize the full strategic and financial benefits currently anticipated from the Transactions, Centennial shareholders will have experienced substantial dilution of their ownership interests without receiving any commensurate benefit, or only receiving part of the commensurate benefit to the extent the combined company is able to realize only part of the strategic and financial benefits currently anticipated from the Transactions.
The combined company may not be able to retain customers, suppliers or distributors, or customers, suppliers or distributors may seek to modify contractual relationships with the combined company, which could have an adverse effect on the combined company’s business and operations. Third parties may terminate or alter existing contracts or relationships with the combined company.
As a result of the Transactions, the combined company may experience impacts on relationships with customers, suppliers and distributors that may harm the combined company’s business and results of operations. Certain customers, suppliers or distributors may seek to terminate or modify contractual obligations following the Transactions whether or not contractual rights are triggered as a result of the Transactions. There can be no guarantee that customers, suppliers and distributors will remain with or continue to have a relationship with the combined company or do so on the same or similar contractual terms following the Transactions. If any customers, suppliers or distributors seek to terminate or modify contractual obligations or discontinue the relationship with the combined company, then the combined company’s business and results of operations may be harmed. If the combined company’s suppliers were to seek to terminate or modify an arrangement with the combined company, then the combined company may be unable to procure necessary supplies from other suppliers in a timely and efficient manner and on acceptable terms, or at all.
We and Colgate also have contracts with third parties which may require consent from these parties in connection with the Transactions, or which may otherwise contain limitations applicable to such contracts following the Transactions. If these consents cannot be obtained, the combined company may suffer a loss of potential future revenue, incur costs and lose rights that may be material to the combined company’s business. In addition, third parties with whom we or Colgate currently have relationships may terminate or otherwise reduce the scope of their relationship in anticipation of the Transactions. Any such disruptions could limit the combined company’s ability to achieve the anticipated benefits of the Transactions. The adverse effect of any such disruptions could also be exacerbated by a delay in the completion of the Transactions or by a termination of the Business Combination Agreement.
Colgate is currently not a U.S. public reporting company and the obligations associated with integrating into a public company may require significant resources and management attention.
Colgate is, and prior to the consummation of the Transactions will remain, a private company that is not subject to reporting requirements and does not have accounting personnel specifically employed to review internal controls over financial reporting. Upon completion of the Transactions, the Colgate business will become subject to the rules and regulations established from time to time by the SEC and Nasdaq. In addition, as a public company, we are required to document and test our internal controls over financial reporting pursuant to
Section 404(b) of the Sarbanes-Oxley Act of 2002, so that our management can certify as to the effectiveness of our internal control over financial reporting in connection with the annual report. Colgate is required to be included in the scope of our internal control over financial reporting in the annual report to be filed with the SEC for the fiscal year following the fiscal year in which the Transactions are consummated and thereafter, which requires us to make and document significant changes to our internal controls over financial reporting. Bringing Colgate into compliance with these rules and regulations and integrating Colgate into our current compliance and accounting system may increase our legal and financial compliance costs, make some activities more difficult, time-consuming or costly and increase demand on our systems and resources. Furthermore, the need to establish the necessary corporate infrastructure to integrate Colgate may divert management’s attention from implementing our growth strategy, which could prevent us from improving our business, financial condition and results of operations. However, the measures we take may not be sufficient to satisfy our obligations as a public company. If we do not continue to develop and implement the right processes and tools to manage our changing enterprise upon the Transactions and maintain our culture, our ability to compete successfully and achieve our business objectives could be impaired, which could negatively impact our business, financial condition and results of operations. In addition, we cannot predict or estimate the amount of additional costs we may incur to bring Colgate into compliance with these requirements. We anticipate that these costs will materially increase our selling, general and administration expenses. In addition, bringing Colgate into compliance with these rules and regulations will increase our legal and financial compliance costs and will make some activities more time- consuming and costly. These additional obligations could have a material adverse effect on our business, financial condition, results of operations and cash flow.
The Proposed Charter will designate the Court of Chancery of the State of Delaware as the sole and exclusive forum for substantially all actions and proceedings that may be initiated by shareholders, which could limit shareholders’ ability to obtain a favorable judicial forum for disputes with the combined company or its directors, officers, employees or agents.
The Proposed Charter will provide that, unless the combined company consents in writing to the selection of an alternative forum, the Court of Chancery of the State of Delaware will, to the fullest extent permitted by applicable law, be the sole and exclusive forum for (i) any derivative action or proceeding brought on behalf of the combined company, (ii) any action asserting a claim of breach of a fiduciary duty owed by any of the directors, officers, employees or agents of the combined company to the combined company or its shareholders, (iii) any action asserting a claim arising pursuant to any provision of the Delaware
General Corporation Law, the Proposed Charter or the combined company’s bylaws or (iv) any action asserting a claim against the combined company that is governed by the internal affairs doctrine, in each such case subject to such Court of Chancery having personal jurisdiction over the indispensable parties named as defendants therein. In the event the Delaware Court of Chancery lacks subject matter jurisdiction, then the sole and exclusive forum for such action or proceeding shall be the federal district court for the District of Delaware. Any person or entity purchasing or otherwise acquiring any interest in shares of the capital stock of the combined company will be deemed to have notice of, and consented to, the provisions of the Proposed Charter described in the preceding sentences.
This provision would not apply to claims brought to enforce a duty or liability created by the Exchange Act, the Securities Act or any other claim for which the federal courts have exclusive jurisdiction. To the extent that any such claims may be based upon federal law claims, Section 27 of the Exchange Act creates exclusive federal jurisdiction over all suits brought to enforce any duty or liability created by the Exchange Act or the rules and regulations thereunder. Furthermore, Section 22 of the Securities Act creates concurrent jurisdiction for federal and state courts over all suits brought to enforce any duty or liability created by the Securities Act or the rules and regulations thereunder. This choice of forum provision may limit a shareholder’s ability to bring a claim in a judicial forum that it finds favorable for disputes with the combined company or the directors, officers, employees or agents of the combined company, which may discourage such lawsuits against the combined company and such persons. Alternatively, if a court were to find these provisions of the Proposed Charter inapplicable to, or unenforceable in respect of, one or more of the specified types of actions or proceedings, the combined company may incur additional costs associated with resolving such matters in other jurisdictions, which could adversely affect the business, financial condition or results of operations of the combined company.
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.
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Exhibit
Number | | Description of Exhibit |
3.12.1 | | SecondBusiness Combination Agreement, dated as of May 19, 2022, by and among Centennial Resource Development, Inc., Centennial Resource Production, LLC, Colgate Energy Partners III, LLC, and, solely for purposes of the specified provisions therein, Colgate Energy Partners Holdings III, LLC (incorporated by reference to Exhibit 2.1 to the Company’s Current Report on Form 8-K filed with the SEC on May 19, 2022). |
| 3.1 | | |
| 3.2 | | |
| 3.3 | | |
| 3.4 | | |
| 3.5 | | |
| 3.6 | | |
| 10.1 | | |
| 10.2 | | Voting and Support Agreement, dated as of May 19, 2022, by and among Centennial Resource Development, Inc., Riverstone VI Centennial QB Holdings, L.P., REL US Centennial Holdings, LLC, Riverstone Non-ECI USRPI AIV, L.P., Silver Run Sponsor, LLC and Colgate Energy Partners III, LLC (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed with the SEC on May 19, 2022) |
| 31.1* | | |
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| 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.
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| CENTENNIAL RESOURCE DEVELOPMENT, INC. |
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| 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, 2017August 4, 2022 |