Centennial Resource Development Announces Third Quarter 2021 Results, Non-Core Divestiture and Increases 2021 Production Targets
DENVER, Nov. 3, 2021 (GLOBE NEWSWIRE) -- Centennial Resource Development, Inc. (“Centennial” or the “Company”) (NASDAQ: CDEV) today announced third quarter 2021 financial and operational results.
Recent Financial and Operational Highlights
•Generated record free cash flow, a 126% increase compared to the prior quarter
•Repaid $50 million in borrowings under the Company’s credit facility during the quarter
•Improved leverage metrics significantly quarter-over-quarter
•Announced pending sale of non-core asset in southern Reeves County, Texas
•Increased daily crude oil production 5% compared to the prior quarter
•Increased full-year oil and total company production guidance
Financial Results
For the third quarter, Centennial generated net cash from operating activities of $153.5 million and free cash flow1 of $77.2 million. The Company reported net income during the quarter of $37.1 million, or $0.12 per diluted share, compared to a net loss of $51.5 million, or $(0.19) loss per diluted share, in the prior year period.
Average daily crude oil production during the third quarter was 33,529 barrels of oil per day (“Bbls/d”) compared to 35,292 Bbls/d in the prior year period. Total equivalent production for the quarter averaged 65,121 barrels of oil equivalent per day (“Boe/d”) compared to 68,934 Boe/d in the prior year period. Third quarter average daily crude oil and total equivalent production increased 5% and 6%, respectively, quarter-over-quarter.
“Centennial delivered a strong third quarter. Solid well results coupled with higher commodity prices drove record free cash flow and a material reduction in leverage,” said Sean R. Smith, Chief Executive Officer. “Assuming receipt of the proceeds from our pending divestiture and strip pricing, we anticipate ending the year with a net debt-to-LTM EBITDAX2 ratio of approximately 1.5x.”
Third Quarter Operational Results
Using multi-well pads and extended laterals, Centennial continues to efficiently develop its Delaware Basin acreage position. In Lea County, New Mexico, the three-well Crunch Berry 6 Federal Com pad (70% working interest (“WI”)) was completed in the Third Bone Spring Sand interval with average 9,500-foot laterals. The wells averaged 2,047 Boe/d, or 1,607 Bbls/d of oil, per well for the 30-day initial production (“IP”) period. “With the robust results from the Crunch Berry wells and current strip prices, we expect these wells to pay-out in less than six months,” said Smith.
Located on the western portion of Centennial’s New Mexico position, the Mozzarella Fed Com (91% WI) and Gouda Federal Com (95% WI) represent a four-well development in the Third Bone Spring Sand interval with average 10,050-foot laterals. The wells averaged 2,147 Boe/d, or 1,615 Bbls/d of oil, per well for the 30-day IP period.
Drilled in the Wolfcamp C interval in Reeves County, Texas with an approximate 8,100-foot lateral, the Highlander West Deep C09H (100% WI) was another strong result for the Company. The well delivered a 30-day IP rate of 1,793 Boe/d (77% oil), or 170 Bbls/d of oil per 1,000 foot of lateral.
Total capital expenditures incurred for the quarter were $78.9 million. Third quarter drilling, completion and facilities costs totaled $74.9 million, while infrastructure, land and other capital expenditures totaled $4.0 million.
“Our operations team has done an excellent job demonstrating capital cost control this year,” said Smith. “Going forward, we will continue to focus on driving further efficiencies, extending lateral lengths and expanding pad sizes to help offset future oilfield service cost inflation.”
Non-Core Divestiture
Centennial recently entered into a definitive agreement with affiliates of Henry Resources, LLC and Pickering Energy Partners, LP for the sale of approximately 6,200 net leasehold acres and related assets at closing for a cash purchase price of $101 million. The divested acreage is located on the southernmost portion of the Company’s Reeves County position. Third quarter estimated average net production associated with the divested acreage was approximately 1,600 Boe/d (64% oil), or less than 3% of total company production. The transaction is expected to close in December of 2021, subject to customary closing terms and conditions, and its impact is included in the Company’s updated 2021 operational targets.
“We are pleased to have monetized this acreage position given that our near-term capital is focused on other areas of our portfolio,” said Smith. “Upon closing, the net proceeds will go to reduce borrowings on the Company’s revolver.”
Updated 2021 Operational Targets
Based on recent operational results, Centennial increased its 2021 total company and oil production guidance by 3% and 2%, respectively. The Company also increased the expected number of wells spud this year due to continued operational efficiencies. As a result of higher than expected activity, Centennial has adjusted its full-year capital expenditure range. Furthermore, Centennial has updated its full-year 2021 production cost estimates. (For a summary table of Centennial’s updated 2021 operational guidance, please see the Appendix to this press release.)
Capital Structure and Liquidity
During the third quarter, Centennial repaid $50.0 million of borrowings under its revolving credit facility, leaving $205.0 million outstanding at September 30, 2021. Total debt at the end of the quarter was $1,020.8 million. Net debt-to-LTM EBITDAX2 at September 30, 2021 was 2.1x compared to 3.0x at June 30, 2021. Centennial’s total liquidity position improved by $47.8 million quarter-over-quarter to $493.5 million, based on its $700.0 million borrowing base, credit facility borrowings, $6.5 million in current letters of credit outstanding and cash on hand as of September 30, 2021.
“Year-to-date, we have repaid $125 million in borrowings under our credit facility primarily utilizing free cash flow,” said Smith. “Assuming current strip pricing and the successful closing of our pending divestiture, we expect to have minimal borrowings under our revolver at year-end. Additionally, our net debt-to-LTM EBITDAX2 metric of 2.1x represents a significant de-leveraging of the balance sheet that is expected to continue in subsequent quarters and will significantly enhance our financial flexibility over time.”
Hedge Position Update
Since its last update on August 3, 2021, the Company has added incremental oil hedges for the full-year 2022. For the first half of 2022, the Company entered into 1,757 Bbls/d of incremental oil swaps at a weighted average fixed
price of $68.42 per barrel WTI. Also for this period, the Company added 2,500 Bbls/d of WTI oil collars with a weighted average floor price of $63.40 per barrel and ceiling price of $73.35 per barrel. For the second half of 2022, the Company entered into 2,000 Bbls/d of incremental oil swaps at a weighted average fixed price of $67.38 per barrel WTI. As a result, Centennial now has a total of 10,971 Bbls/d of oil hedged for the full-year 2022, consisting of approximately 89% fixed price swaps with the remainder in costless collars. Notably, the Company’s oil hedges are weighted towards the first half of 2022 with 14,500 Bbls/d of oil hedged during this period. For the second half of 2022, Centennial has 7,500 Bbls/d of oil hedged.
In addition to the 2022 hedge positions discussed above, Centennial has certain other crude oil and natural gas hedges, crude oil and natural gas basis swaps and crude oil roll differential swaps in place. (For a summary table of Centennial’s derivative contracts as of October 31, 2021, please see the Appendix to this press release.)
Quarterly Report on Form 10-Q
Centennial’s financial statements and related footnotes will be available in its Quarterly Report on Form 10-Q for the quarter ended September 30, 2021, which is expected to be filed with the U.S. Securities and Exchange Commission (“SEC”) on November 4, 2021.
Conference Call and Webcast
Centennial will host an investor conference call on Thursday, November 4, 2021 at 8:00 a.m. Mountain (10:00 a.m. Eastern) to discuss third quarter 2021 operating and financial results. Interested parties may join the webcast by visiting Centennial’s website at www.cdevinc.com and clicking on the webcast link or by dialing (844) 348-0017, or (213) 358-0877 for international calls, (Conference ID: 6880769) at least 15 minutes prior to the start of the call. A replay of the call will be available on Centennial’s website or by phone at (855) 859-2056 (Conference ID: 6880769) for a seven-day period following the call.
About Centennial Resource Development, Inc.
Centennial Resource Development, Inc. is an independent oil and natural gas company focused on the development of oil and associated liquids-rich natural gas reserves in the Permian Basin. The Company’s assets and operations, which are held and conducted through Centennial Resource Production, LLC, are concentrated in the Delaware Basin, a sub-basin of the Permian Basin. For additional information about the Company, please visit www.cdevinc.com.
Cautionary Note Regarding Forward-Looking Statements
The information in this press release includes “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. All statements, other than statements of historical fact included in this press release, 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 press release, the words “could,” “may,” “believe,” “anticipate,” “intend,” “estimate,” “expect,” “project,” “goal,” “plan,” “target” and similar expressions are intended to identify forward-looking statements, although not all forward-looking statements contain such identifying words. These forward-looking statements are based on management’s current expectations and assumptions about future events and are based on currently available information as to the outcome and timing of future events.
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 reduced demand caused by the COVID-19 pandemic and the actions taken in response by certain oil and natural gas producing countries;
•our business strategy and future drilling plans;
•our reserves and our ability to replace the reserves we produce through drilling and property acquisitions;
•our drilling prospects, inventories, projects and programs;
•our financial strategy, 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 competition and government regulations;
•our ability to obtain permits and governmental approvals;
•our pending legal or environmental matters;
•the marketing and transportation of our oil, natural gas and NGLs;
•our leasehold or business acquisitions;
•cost of developing our properties;
•our anticipated rate of return;
•general economic conditions;
•weather conditions in the areas where we operate;
•credit markets;
•uncertainty regarding our future operating results;
•our plans, objectives, expectations and intentions contained in this press release that are not historical; and
•the other factors described in our most recent Annual Report on Form 10-K, and any updates to those factors set forth in our subsequent Quarterly Reports on Form 10-Q or Current Reports on Form 8-K.
We caution you that these forward-looking statements are subject to all of the risks and uncertainties, most of which are difficult to predict and many 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, commodity 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 oil and gas reserves and in projecting future rates of production, cash flow and access to capital, the timing of development expenditures and the other risks described in our filings with the SEC.
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 oil and gas 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.
Should one or more of the risks or uncertainties described in this press release occur, or should underlying assumptions prove incorrect, our actual results and plans could differ materially from those expressed in any forward-looking statements. All forward-looking statements, expressed or implied, included in this press release 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 statements in this section, to reflect events or circumstances after the date of this press release.
1) Free Cash Flow is a non-GAAP financial measure. See “Non-GAAP Financial Measures” included within the Appendix of this press release for related disclosures and a reconciliation to net cash provided by operating activities, our most directly comparable financial measure calculated and presented in accordance with GAAP.
2) Net debt-to-LTM EBITDAX is a non-GAAP financial measure. The Company defines net debt as long-term debt, net, plus unamortized debt discount and debt issuance costs on senior notes minus cash and cash equivalents. The Company defines net debt-to-LTM EBITDAX as net debt (defined above) divided by Adjusted EBITDAX (defined and reconciled in the Appendix of this press release for the three and nine month periods ended September 30, 2021 and 2020) for the prior twelve-month period. The Company refers to this metric to show trends that investors may find useful in understanding the Company’s ability to service its debt. This metric is widely used by professional research analysts, including credit analysts, in the valuation and comparison of companies in the oil and gas exploration and production industry. Centennial does not provide guidance on the items used to reconcile between forecasted net debt-to-LTM EBITDAX to forecasted long-term debt, net, or forecasted net income due to the uncertainty regarding timing and estimates of certain items. Therefore, Centennial cannot reconcile forecasted net debt-to-LTM EBITDAX to forecasted long-term debt, net, or forecasted net income without unreasonable effort.
Contact:
Hays Mabry
Sr. Director, Investor Relations
(832) 240-3265
ir@cdevinc.com
SOURCE Centennial Resource Development, Inc.
Details of our updated 2021 operational and financial guidance are presented below:
| 2021 FY Guidance (Updated) | ||||||||||||||
| Net average daily production (Boe/d) | 60,500 | — | 61,850 | |||||||||||
| Net average daily oil production (Bbls/d) | 31,500 | — | 32,150 | |||||||||||
| Production costs | ||||||||||||||
| Lease operating expenses ($/Boe) | $4.65 | — | $4.80 | |||||||||||
| Gathering, processing and transportation expenses ($/Boe) | $3.90 | — | $4.00 | |||||||||||
| Depreciation, depletion, and amortization ($/Boe) | $12.75 | — | $13.25 | |||||||||||
Cash general and administrative ($/Boe)1 | $2.05 | — | $2.10 | |||||||||||
Stock-based compensation ($/Boe)2 | $2.95 | — | $3.05 | |||||||||||
| Severance and ad valorem taxes (% of revenue) | 6.0% | — | 7.0% | |||||||||||
| Capital expenditure program ($MM) | $300 | — | $315 | |||||||||||
| Drilling, completion and facilities | $290 | — | $305 | |||||||||||
| Infrastructure, land and other | ~$10 | |||||||||||||
| Operated drilling program | ||||||||||||||
| Wells spud (gross) | 46 | — | 50 | |||||||||||
| Wells completed (gross) | 41 | — | 43 | |||||||||||
| Average working interest | ~90% | |||||||||||||
| Average lateral length (feet) | ~8,800 | |||||||||||||
(1) Cash general and administrative guidance does not include the portion of stock-based compensation that was settled in cash during fiscal year 2021.
(2) Stock-based compensation guidance includes expense amounts for both equity awards and for cash-based liability awards. The amount of actual expense to be incurred for certain awards included in this guidance range may vary from our forecast, as such expense can fluctuate materially in future periods with changes in Centennial’s stock price and with changes in Centennial’s stock price performance versus a defined peer group of companies. Liability award amounts totaling $5.9 million were settled in cash during fiscal year 2021.
Centennial Resource Development, Inc.
Operating Highlights
| Three Months Ended September 30, | Nine Months Ended September 30, | ||||||||||||||||||||||
| 2021 | 2020 | 2021 | 2020 | ||||||||||||||||||||
| Net revenues (in thousands): | |||||||||||||||||||||||
| Oil sales | $ | 201,447 | $ | 119,966 | $ | 512,278 | $ | 363,571 | |||||||||||||||
| Natural gas sales | 43,800 | 11,907 | 106,266 | 29,052 | |||||||||||||||||||
| NGL sales | 43,258 | 17,228 | 94,929 | 39,756 | |||||||||||||||||||
| Oil and gas sales | $ | 288,505 | $ | 149,101 | $ | 713,473 | $ | 432,379 | |||||||||||||||
| Average sales prices: | |||||||||||||||||||||||
| Oil (per Bbl) | $ | 65.31 | $ | 36.95 | $ | 60.05 | $ | 34.86 | |||||||||||||||
| Effect of derivative settlements on average price (per Bbl) | (8.37) | (9.82) | (10.12) | (3.58) | |||||||||||||||||||
| Oil net of hedging (per Bbl) | $ | 56.94 | $ | 27.13 | $ | 49.93 | $ | 31.28 | |||||||||||||||
| Average NYMEX price for oil (per Bbl) | $ | 70.56 | $ | 40.93 | $ | 64.82 | $ | 38.37 | |||||||||||||||
| Oil differential from NYMEX | (5.25) | (3.98) | (4.77) | (3.51) | |||||||||||||||||||
| Natural gas (per Mcf) | $ | 3.99 | $ | 1.15 | $ | 3.44 | $ | 0.93 | |||||||||||||||
| Effect of derivative settlements on average price (per Mcf) | (0.27) | (0.25) | (0.09) | (0.13) | |||||||||||||||||||
| Natural gas net of hedging (per Mcf) | $ | 3.72 | $ | 0.90 | $ | 3.35 | $ | 0.80 | |||||||||||||||
| Average NYMEX price for natural gas (per Mcf) | $ | 4.28 | $ | 1.95 | $ | 3.53 | $ | 1.82 | |||||||||||||||
| Natural gas differential from NYMEX | (0.29) | (0.80) | (0.09) | (0.89) | |||||||||||||||||||
| NGL (per Bbl) | $ | 40.16 | $ | 12.58 | $ | 33.98 | $ | 11.50 | |||||||||||||||
| Net production: | |||||||||||||||||||||||
| Oil (MBbls) | 3,085 | 3,247 | 8,531 | 10,429 | |||||||||||||||||||
| Natural gas (MMcf) | 10,977 | 10,354 | 30,933 | 31,209 | |||||||||||||||||||
| NGL (MBbls) | 1,077 | 1,370 | 2,794 | 3,458 | |||||||||||||||||||
Total (MBoe)(1) | 5,991 | 6,342 | 16,479 | 19,088 | |||||||||||||||||||
| Average daily net production: | |||||||||||||||||||||||
| Oil (Bbls/d) | 33,529 | 35,292 | 31,246 | 38,061 | |||||||||||||||||||
| Natural gas (Mcf/d) | 119,311 | 112,545 | 113,305 | 113,900 | |||||||||||||||||||
| NGL (Bbls/d) | 11,707 | 14,885 | 10,233 | 12,619 | |||||||||||||||||||
Total (Boe/d)(1) | 65,121 | 68,934 | 60,363 | 69,664 | |||||||||||||||||||
(1) Calculated by converting natural gas to oil equivalent barrels at a ratio of six Mcf of natural gas to one Boe.
Centennial Resource Development, Inc.
Operating Expenses
| Three Months Ended September 30, | Nine Months Ended September 30, | ||||||||||||||||||||||
| 2021 | 2020 | 2021 | 2020 | ||||||||||||||||||||
| Operating costs (in thousands): | |||||||||||||||||||||||
| Lease operating expenses | $ | 28,685 | $ | 24,543 | $ | 77,522 | $ | 83,021 | |||||||||||||||
| Severance and ad valorem taxes | 17,800 | 7,839 | 46,167 | 30,108 | |||||||||||||||||||
| Gathering, processing and transportation expenses | 24,164 | 19,130 | 64,283 | 53,353 | |||||||||||||||||||
| Operating cost metrics: | |||||||||||||||||||||||
| Lease operating expenses (per Boe) | $ | 4.79 | $ | 3.87 | $ | 4.70 | $ | 4.35 | |||||||||||||||
| Severance and ad valorem taxes (% of revenue) | 6.2 | % | 5.3 | % | 6.5 | % | 7.0 | % | |||||||||||||||
| Gathering, processing and transportation expenses (per Boe) | $ | 4.03 | $ | 3.02 | $ | 3.90 | $ | 2.80 | |||||||||||||||
Centennial Resource Development, Inc.
Consolidated Statements of Operations (unaudited)
(in thousands, except per share data)
| Three Months Ended September 30, | Nine Months Ended September 30, | ||||||||||||||||||||||
| 2021 | 2020 | 2021 | 2020 | ||||||||||||||||||||
| Operating revenues | |||||||||||||||||||||||
| Oil and gas sales | $ | 288,505 | $ | 149,101 | $ | 713,473 | $ | 432,379 | |||||||||||||||
| Operating expenses | |||||||||||||||||||||||
| Lease operating expenses | 28,685 | 24,543 | 77,522 | 83,021 | |||||||||||||||||||
| Severance and ad valorem taxes | 17,800 | 7,839 | 46,167 | 30,108 | |||||||||||||||||||
Gathering, processing and transportation expenses | 24,164 | 19,130 | 64,283 | 53,353 | |||||||||||||||||||
| Depreciation, depletion and amortization | 76,047 | 89,444 | 213,259 | 283,722 | |||||||||||||||||||
| Impairment and abandonment expense | 7,712 | 19,904 | 26,111 | 650,629 | |||||||||||||||||||
| Exploration and other expenses | 1,839 | 2,670 | 4,698 | 10,730 | |||||||||||||||||||
| General and administrative expenses | 35,748 | 17,582 | 89,811 | 54,446 | |||||||||||||||||||
| Total operating expenses | 191,995 | 181,112 | 521,851 | 1,166,009 | |||||||||||||||||||
| Net gain (loss) on sale of long-lived assets | (290) | 145 | (254) | 388 | |||||||||||||||||||
| Proceeds from terminated sale of assets | — | — | 5,983 | — | |||||||||||||||||||
| Income (loss) from operations | 96,220 | (31,866) | 197,351 | (733,242) | |||||||||||||||||||
| Other income (expense) | |||||||||||||||||||||||
| Interest expense | (14,690) | (17,718) | (47,357) | (51,510) | |||||||||||||||||||
| Gain (loss) on extinguishment of debt | — | — | (22,156) | 143,443 | |||||||||||||||||||
| Net gain (loss) on derivative instruments | (44,527) | (1,968) | (150,685) | (40,330) | |||||||||||||||||||
| Other income (expense) | 121 | 23 | 271 | (29) | |||||||||||||||||||
Total other income (expense) | (59,096) | (19,663) | (219,927) | 51,574 | |||||||||||||||||||
| Income (loss) before income taxes | 37,124 | (51,529) | (22,576) | (681,668) | |||||||||||||||||||
| Income tax (expense) benefit | — | — | — | 85,124 | |||||||||||||||||||
| Net income (loss) | 37,124 | (51,529) | (22,576) | (596,544) | |||||||||||||||||||
Less: Net (income) loss attributable to noncontrolling interest | — | — | — | 2,362 | |||||||||||||||||||
| Net income (loss) attributable to Class A Common Stock | $ | 37,124 | $ | (51,529) | $ | (22,576) | $ | (594,182) | |||||||||||||||
| Income (loss) per share of Class A Common Stock: | |||||||||||||||||||||||
| Basic | $ | 0.13 | $ | (0.19) | $ | (0.08) | $ | (2.14) | |||||||||||||||
| Diluted | $ | 0.12 | $ | (0.19) | $ | (0.08) | $ | (2.14) | |||||||||||||||
Centennial Resource Development, Inc.
Consolidated Balance Sheets (unaudited)
(in thousands, except share and per share data)
| September 30, 2021 | December 31, 2020 | ||||||||||
| ASSETS | |||||||||||
| Current assets | |||||||||||
| Cash and cash equivalents | $ | 4,985 | $ | 5,800 | |||||||
| Accounts receivable, net | 99,851 | 54,557 | |||||||||
| Prepaid and other current assets | 4,710 | 5,229 | |||||||||
| Total current assets | 109,546 | 65,586 | |||||||||
| Property and Equipment | |||||||||||
| Oil and natural gas properties, successful efforts method | |||||||||||
| Unproved properties | 1,151,552 | 1,209,205 | |||||||||
| Proved properties | 4,662,364 | 4,395,473 | |||||||||
| Accumulated depreciation, depletion and amortization | (2,088,128) | (1,877,832) | |||||||||
| Total oil and natural gas properties, net | 3,725,788 | 3,726,846 | |||||||||
| Other property and equipment, net | 11,544 | 12,650 | |||||||||
| Total property and equipment, net | 3,737,332 | 3,739,496 | |||||||||
| Noncurrent assets | |||||||||||
| Operating lease right-of-use assets | 17,656 | 3,176 | |||||||||
| Other noncurrent assets | 17,807 | 19,167 | |||||||||
| TOTAL ASSETS | $ | 3,882,341 | $ | 3,827,425 | |||||||
| LIABILITIES AND EQUITY | |||||||||||
| Current liabilities | |||||||||||
| Accounts payable and accrued expenses | $ | 150,611 | $ | 110,439 | |||||||
| Operating lease liabilities | 1,522 | 3,155 | |||||||||
| Other current liabilities | 76,403 | 18,274 | |||||||||
| Total current liabilities | 228,536 | 131,868 | |||||||||
| Noncurrent liabilities | |||||||||||
| Long-term debt, net | 1,004,937 | 1,068,624 | |||||||||
| Asset retirement obligations | 17,710 | 17,009 | |||||||||
| Deferred income taxes | 2,589 | 2,589 | |||||||||
| Operating lease liabilities | 16,689 | 422 | |||||||||
| Other noncurrent liabilities | 27,232 | 2,952 | |||||||||
| Total liabilities | 1,297,693 | 1,223,464 | |||||||||
Commitments and contingencies (Note 11) | |||||||||||
| Shareholders’ equity | |||||||||||
| Common stock, $0.0001 par value, 620,000,000 shares authorized: | |||||||||||
Class A: 294,280,467 shares issued and 284,084,602 shares outstanding at September 30, 2021 and 290,645,623 shares issued and 278,551,901 shares outstanding at December 31, 2020 | 29 | 29 | |||||||||
| Additional paid-in capital | 3,007,696 | 3,004,433 | |||||||||
| Retained earnings (accumulated deficit) | (423,077) | (400,501) | |||||||||
| Total shareholders’ equity | 2,584,648 | 2,603,961 | |||||||||
| Noncontrolling interest | — | — | |||||||||
| Total equity | 2,584,648 | 2,603,961 | |||||||||
| TOTAL LIABILITIES AND EQUITY | $ | 3,882,341 | $ | 3,827,425 | |||||||
Centennial Resource Development, Inc.
Consolidated Statements of Cash Flows (unaudited)
(in thousands)
| Nine Months Ended September 30, | |||||||||||
| 2021 | 2020 | ||||||||||
| Cash flows from operating activities: | |||||||||||
| Net income (loss) | $ | (22,576) | $ | (596,544) | |||||||
| Adjustments to reconcile net income (loss) to net cash provided by operating activities: | |||||||||||
| Depreciation, depletion and amortization | 213,259 | 283,722 | |||||||||
| Stock-based compensation expense - equity awards | 32,299 | 16,164 | |||||||||
| Stock-based compensation expense - liability awards | 19,950 | — | |||||||||
| Impairment and abandonment expense | 26,111 | 650,629 | |||||||||
| Deferred tax expense (benefit) | — | (85,124) | |||||||||
| Net (gain) loss on sale of long-lived assets | 254 | (388) | |||||||||
| Non-cash portion of derivative (gain) loss | 61,490 | (1,103) | |||||||||
| Amortization of debt issuance costs and debt discount | 3,935 | 4,112 | |||||||||
| (Gain) loss on extinguishment of debt | 22,156 | (143,443) | |||||||||
| Changes in operating assets and liabilities: | |||||||||||
| (Increase) decrease in accounts receivable | (42,998) | 48,139 | |||||||||
| (Increase) decrease in prepaid and other assets | 1,803 | (2,825) | |||||||||
| Increase (decrease) in accounts payable and other liabilities | 17,449 | (43,107) | |||||||||
| Net cash provided by operating activities | 333,132 | 130,232 | |||||||||
| Cash flows from investing activities: | |||||||||||
| Acquisition of oil and natural gas properties | (4,285) | (7,689) | |||||||||
| Drilling and development capital expenditures | (215,358) | (300,660) | |||||||||
| Purchases of other property and equipment | (686) | (1,035) | |||||||||
| Proceeds from sales of oil and natural gas properties | 4,011 | 1,375 | |||||||||
| Net cash used in investing activities | (216,318) | (308,009) | |||||||||
| Cash flows from financing activities: | |||||||||||
| Proceeds from borrowings under revolving credit facility | 450,000 | 490,000 | |||||||||
| Repayment of borrowings under revolving credit facility | (575,000) | (310,000) | |||||||||
| Proceeds from issuance of convertible senior notes | 170,000 | — | |||||||||
| Debt issuance costs | (6,421) | (6,650) | |||||||||
| Premiums paid on capped call transactions | (14,688) | — | |||||||||
| Redemption of senior secured notes | (127,073) | — | |||||||||
| Proceeds from exercise of stock options | 15 | — | |||||||||
| Restricted stock used for tax withholdings | (14,459) | (598) | |||||||||
| Net cash (used in) provided by financing activities | (117,626) | 172,752 | |||||||||
| Net increase (decrease) in cash, cash equivalents and restricted cash | (812) | (5,025) | |||||||||
| Cash, cash equivalents and restricted cash, beginning of period | 8,339 | 15,543 | |||||||||
| Cash, cash equivalents and restricted cash, end of period | $ | 7,527 | $ | 10,518 | |||||||
Reconciliation of cash, cash equivalents and restricted cash presented on the Consolidated Statements of Cash Flows for the periods presented:
| Nine Months Ended September 30, | |||||||||||
| 2021 | 2020 | ||||||||||
| Cash and cash equivalents | $ | 4,985 | $ | 5,177 | |||||||
| Restricted cash | 2,542 | 5,341 | |||||||||
| Total cash, cash equivalents and restricted cash | $ | 7,527 | $ | 10,518 | |||||||
Non-GAAP Financial Measures
In addition to disclosing financial results calculated in accordance with U.S. generally accepted accounting principles (“GAAP”), our earnings release contains non-GAAP financial measures as described below.
Adjusted EBITDAX
Adjusted EBITDAX is a supplemental non-GAAP financial measure that is used by management and external users of our consolidated financial statements, such as industry analysts, investors, lenders and rating agencies. We define Adjusted EBITDAX as net income before interest expense, income taxes, depreciation, depletion and amortization, exploration and other expenses, impairment and abandonment expenses, non-cash gains or losses on derivatives, stock-based compensation (not cash-settled), gain/loss on extinguishment of debt, gain/loss from the sale of assets and non-recurring items. Adjusted EBITDAX is not a measure of net income as determined by GAAP.
Our management believes Adjusted EBITDAX is useful as it allows them to more effectively evaluate our operating performance and compare the results of our operations from period to period and against our peers, without regard to our financing methods or capital structure. We exclude the items listed above from net income in arriving at Adjusted EBITDAX because these amounts can vary substantially from company to company within our industry depending upon accounting methods and book values of assets, capital structures and the method by which the assets were acquired. Adjusted EBITDAX should not be considered as an alternative to, or more meaningful than, net income as determined in accordance with GAAP or as an indicator of our operating performance or liquidity. Certain items excluded from Adjusted EBITDAX are significant components in understanding and assessing a company’s financial performance, such as a company’s cost of capital and tax structure, as well as the historic costs of depreciable assets, none of which are components of Adjusted EBITDAX. Our presentation of Adjusted EBITDAX should not be construed as an inference that our results will be unaffected by unusual or nonrecurring items. Our computations of Adjusted EBITDAX may not be comparable to other similarly titled measures of other companies.
The following table presents a reconciliation of Adjusted EBITDAX to net income, which is the most directly comparable financial measure calculated and presented in accordance with GAAP:
| Three Months Ended September 30, | Nine Months Ended September 30, | ||||||||||||||||||||||
| (in thousands) | 2021 | 2020 | 2021 | 2020 | |||||||||||||||||||
Adjusted EBITDAX reconciliation to net income: | |||||||||||||||||||||||
Net income (loss) attributable to Class A Common Stock | $ | 37,124 | $ | (51,529) | $ | (22,576) | $ | (594,182) | |||||||||||||||
Net income (loss) attributable to noncontrolling interest | — | — | — | (2,362) | |||||||||||||||||||
Interest expense | 14,690 | 17,718 | 47,357 | 51,510 | |||||||||||||||||||
Income tax expense (benefit) | — | — | — | (85,124) | |||||||||||||||||||
Depreciation, depletion and amortization | 76,047 | 89,444 | 213,259 | 283,722 | |||||||||||||||||||
Impairment and abandonment expenses | 7,712 | 19,904 | 26,111 | 650,629 | |||||||||||||||||||
(Gain) loss on extinguishment of debt | — | — | 22,156 | (143,443) | |||||||||||||||||||
Non-cash derivative (gain) loss | 15,731 | (32,518) | 61,490 | (1,103) | |||||||||||||||||||
Stock-based compensation expense(1) | 17,421 | 4,772 | 50,726 | 14,934 | |||||||||||||||||||
| Exploration and other expenses | 1,839 | 2,670 | 4,698 | 10,730 | |||||||||||||||||||
| Workforce reduction severance payments | — | 582 | — | 3,466 | |||||||||||||||||||
Transaction costs | — | — | — | 476 | |||||||||||||||||||
(Gain) loss on sale of long-lived assets | 290 | (145) | 254 | (388) | |||||||||||||||||||
| Proceeds from terminated sale of assets | — | — | (5,983) | — | |||||||||||||||||||
Adjusted EBITDAX | $ | 170,854 | $ | 50,898 | $ | 397,492 | $ | 188,865 | |||||||||||||||
(1) Includes stock-based compensation for equity awards and also for cash-based liability awards that have not yet been settled in cash, both of which relate to general and administrative employees only. Stock-based compensation amounts for geographical and geophysical personnel are included within the Exploration and other expenses line item.
Free Cash Flow
Free cash flow is a supplemental non-GAAP financial measure that is used by management and external users of our consolidated financial statements, such as industry analysts, investors, lenders and rating agencies. We define free cash flow as net cash provided by operating activities before changes in working capital, less incurred capital expenditures.
Our management believes free cash flow is a useful indicator of the Company’s ability to internally fund its exploration and development activities and to service or incur additional debt, without regard to the timing of settlement of either operating assets and liabilities or accounts payable related to capital expenditures. The Company believes that this measure, as so adjusted, presents a meaningful indicator of the Company’s actual sources and uses of capital associated with its operations conducted during the applicable period. Our computations of free cash flow may not be comparable to other similarly titled measures of other companies. Free cash flow should not be considered as an alternative to, or more meaningful than, cash provided by operating activities as determined in accordance with GAAP or as indicator of our operating performance or liquidity.
Free cash flow is not a financial measure that is determined in accordance with GAAP. Accordingly, the following table presents a reconciliation of free cash flow to net cash provided by operating activities, which is the most directly comparable financial measure calculated and presented in accordance with GAAP:
| Three Months Ended September 30, | |||||||||||
| (in thousands) | 2021 | 2020 | |||||||||
| Net cash provided by operating activities | $ | 153,507 | $ | 45,729 | |||||||
| Changes in working capital: | |||||||||||
| Accounts receivable | 9,515 | (12,074) | |||||||||
| Prepaid and other assets | (1,812) | 2,866 | |||||||||
| Accounts payable and other liabilities | (5,148) | (4,559) | |||||||||
| Discretionary cash flow | 156,062 | 31,962 | |||||||||
| Less: total capital expenditures incurred | (78,900) | (21,500) | |||||||||
| Free cash flow | $ | 77,162 | $ | 10,462 | |||||||
The following tables summarize the approximate volumes and average contract prices of hedge contracts the Company had in place as of September 30, 2021 and additional contracts entered into through October 31, 2021:
| Period | Volume (Bbls) | Volume (Bbls/d) | Wtd. Avg. Crude Price ($/Bbl)(1) | ||||||||||||||||||||
| Crude oil swaps | |||||||||||||||||||||||
| NYMEX WTI | October 2021 - December 2021 | 828,000 | 9,000 | $49.82 | |||||||||||||||||||
| January 2022 - March 2022 | 1,080,000 | 12,000 | 65.03 | ||||||||||||||||||||
| April 2022 - June 2022 | 1,092,000 | 12,000 | 65.28 | ||||||||||||||||||||
| July 2022 - September 2022 | 736,000 | 8,000 | 64.53 | ||||||||||||||||||||
| October 2022 - December 2022 | 644,000 | 7,000 | 64.58 | ||||||||||||||||||||
| January 2023 - March 2023 | 45,000 | 500 | 69.41 | ||||||||||||||||||||
| April 2023 - June 2023 | 45,500 | 500 | 68.08 | ||||||||||||||||||||
| ICE Brent | October 2021 - December 2021 | 322,000 | 3,500 | $58.10 | |||||||||||||||||||
| Period | Volume (Bbls) | Volume (Bbls/d) | Wtd. Avg. Collar Price Ranges ($/Bbl)(2) | ||||||||||||||||||||
| Crude oil collars | |||||||||||||||||||||||
NYMEX WTI | October 2021 - December 2021 | 92,000 | 1,000 | $42.00 - $50.10 | |||||||||||||||||||
| January 2022 - March 2022 | 225,000 | 2,500 | 63.60 - 74.30 | ||||||||||||||||||||
| April 2022 - June 2022 | 227,500 | 2,500 | 63.20 - 72.41 | ||||||||||||||||||||
| ICE Brent | October 2021 - December 2021 | 138,000 | 1,500 | $66.67 - $74.80 | |||||||||||||||||||
| Period | Volume (Bbls) | Volume (Bbls/d) | Wtd. Avg. Differential ($/Bbl)(3) | ||||||||||||||||||||
| Crude oil basis differential swaps | October 2021 - December 2021 | 644,000 | 7,000 | $0.26 | |||||||||||||||||||
| January 2022 - March 2022 | 450,000 | 5,000 | 0.22 | ||||||||||||||||||||
| April 2022 - June 2022 | 455,000 | 5,000 | 0.22 | ||||||||||||||||||||
| July 2022 - September 2022 | 460,000 | 5,000 | 0.22 | ||||||||||||||||||||
| October 2022 - December 2022 | 460,000 | 5,000 | 0.22 | ||||||||||||||||||||
| Period | Volume (Bbls) | Volume (Bbls/d) | Wtd. Avg. Differential ($/Bbl)(4) | ||||||||||||||||||||
Crude oil roll differential swaps | January 2022 - March 2022 | 900,000 | 10,000 | $0.71 | |||||||||||||||||||
| April 2022 - June 2022 | 910,000 | 10,000 | 0.71 | ||||||||||||||||||||
| July 2022 - September 2022 | 920,000 | 10,000 | 0.71 | ||||||||||||||||||||
| October 2022 - December 2022 | 920,000 | 10,000 | 0.71 | ||||||||||||||||||||
(1) These crude oil swap transactions are settled based on either the NYMEX WTI or ICE Brent oil price, as applicable, on each trading day within the specified monthly settlement period versus the contractual swap price for the volumes stipulated.
(2) These crude oil collars are settled based on the NYMEX WTI or ICE Brent index price, as applicable, on each trading day within the specified monthly settlement period versus the contractual floor and ceiling prices for the volumes stipulated.
(3) These crude oil basis swap transactions are settled based on the difference between the arithmetic average of ARGUS MIDLAND WTI and ARGUS WTI CUSHING indices, during each applicable monthly settlement period.
(4) These crude oil roll swap transactions are settled based on the difference between the arithmetic average of NYMEX WTI calendar month prices and the physical crude oil delivery month price.
| Period | Volume (MMBtu) | Volume (MMBtu/d) | Wtd. Avg. Gas Price ($/MMBtu)(1) | ||||||||||||||||||||
| Natural gas swaps | October 2021 - December 2021 | 3,680,000 | 40,000 | $2.95 | |||||||||||||||||||
| January 2022 - March 2022 | 2,700,000 | 30,000 | 3.00 | ||||||||||||||||||||
| April 2022 - June 2022 | 2,730,000 | 30,000 | 3.24 | ||||||||||||||||||||
| July 2022 - September 2022 | 2,760,000 | 30,000 | 3.24 | ||||||||||||||||||||
| October 2022 - December 2022 | 1,540,000 | 16,739 | 3.15 | ||||||||||||||||||||
| Period | Volume (MMBtu) | Volume (MMBtu/d) | Wtd. Avg. Differential ($/MMBtu)(2) | ||||||||||||||||||||
| Natural gas basis differential swaps | October 2021 - December 2021 | 4,290,000 | 46,630 | $(0.24) | |||||||||||||||||||
| January 2022 - March 2022 | 2,700,000 | 30,000 | (0.18) | ||||||||||||||||||||
| Period | Volume (MMBtu) | Volume (MMBtu/d) | Wtd. Avg. Collar Price Ranges ($/MMBtu)(3) | ||||||||||||||||||||
Natural gas collars | October 2021 - December 2021 | 1,220,000 | 13,261 | $3.15 - $4.65 | |||||||||||||||||||
| January 2022 - March 2022 | 1,800,000 | 20,000 | 3.15 - 4.65 | ||||||||||||||||||||
| April 2022 - June 2022 | 910,000 | 10,000 | 3.00 - 3.68 | ||||||||||||||||||||
| July 2022 - September 2022 | 920,000 | 10,000 | 3.00 - 3.68 | ||||||||||||||||||||
| October 2022 - December 2022 | 310,000 | 3,370 | 3.00 - 3.68 | ||||||||||||||||||||
(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 Henry Hub price on each trading day within the specified monthly settlement period versus the contractual floor and ceiling prices for the volumes stipulated.