Centennial Resource Development Launches Shareholder Return Program and Announces Full Year 2021 Results and 2022 Guidance
Shareholder Return Program
- Announced
$350 million stock repurchase program - Supported by robust two-year outlook and resilient through commodity price cycles
Recent Financial and Operational Highlights
- Generated record free cash flow1 of
$85 million in the fourth quarter, and over$200 million for the full year - Closed the previously announced non-core asset divestiture in
Reeves County for$101 million - Repaid
$180 million in borrowings during the fourth quarter - Reduced leverage metrics
- Delivered three of the top ten wells in Company history
- Increased daily crude oil production 3% compared to the prior quarter
- Entered into a new
$750 million , five-year revolving credit facility
2022 Financial and Operational Plan
- Expect to generate over
$400 million in free cash flow assuming current strip pricing - Plan to maintain two-rig drilling program
- Expect to deliver 10% to 15% crude oil production growth year-over-year, adjusted for recent divestiture
- Anticipate further reduction in leverage and total debt outstanding
Financial Results
For the full year 2021, Centennial generated net cash from operating activities of
Full year total equivalent production averaged 60,939 barrels of oil equivalent per day (“Boe/d”) compared to 67,161 Boe/d in the prior year. Average daily crude oil production during the full year was 32,058 barrels of oil per day (“Bbls/d”) compared to 36,084 Bbls/d in the prior year. For the fourth quarter, total equivalent production was 62,649 Boe/d compared to 59,708 Boe/d in the prior year period, an increase of 5%. Average daily crude oil production for the quarter increased 14% to average 34,468 Bbls/d compared to 30,196 Bbls/d in the prior year period.
“2021 was an excellent year for Centennial. We generated over
Stock Repurchase Program
Centennial announced a
“I am pleased to announce our first step in returning capital to shareholders through a disciplined share buyback program, which we believe will drive value creation in today’s environment,” said Smith. “The program is supported by a robust two-year outlook, during which we expect to generate over
Smith continued, “We remain focused on further balance sheet improvement and expect to initiate our share repurchase program after achieving our leverage target, which is anticipated to occur during the second quarter of this year assuming current strip prices. Importantly, the execution of this program is not contingent on current strip pricing and is resilient through commodity price cycles, all while maintaining a leverage ratio of 1.0x or less.”
Repurchases under the program may be made from time to time in the open markets or in privately negotiated transactions at the Company’s discretion and are subject to market conditions, applicable legal requirements, available liquidity, compliance with the Company’s debt and other agreements and other factors. The program does not require any specific number of shares to be reacquired and can be modified or discontinued by the Board of Directors at any time.
Fourth Quarter Operational Results
Centennial has continued to efficiently develop its
“These wells generated outstanding results and now represent three of the top ten wells drilled in the Company’s history, based on 90-day rates,” said Smith. “This development highlights the quality of our asset base and our technical expertise, averaging almost 1,700 barrels of oil per day during the first ninety days.”
Also targeting the Second Bone Spring Sand, the
Total capital expenditures incurred for the quarter were
2022 Operational Plans and Targets
In 2022, Centennial plans to continue operating its current two-rig drilling program, which is estimated to generate over
The estimated fiscal year 2022 total capital budget is approximately
During 2022, Centennial anticipates that approximately 80% of its completions will be in
Capital Structure and Liquidity
During the fourth quarter, Centennial repaid
On
“During 2021, we repaid
Year-End 2021 Proved Reserves
Centennial reported year-end 2021 total proved reserves of 305 MMBoe compared to 299 MMBoe at prior year-end. At year-end 2021, proved reserves consisted of 50% oil, 32% natural gas and 18% natural gas liquids. Proved developed reserves were 163 MMBoe (53% of total proved reserves) at
Hedge Position Update
Since its last update on
For the full year 2023, Centennial has a total of 3,740 Bbls/d of oil hedged, consisting of approximately 47% fixed price swaps. The Company currently has 1,744 Bbls/d of oil hedged at a weighted average fixed price of
Annual Report on Form 10-K
Centennial’s financial statements and related footnotes will be available in its Annual Report on Form 10-K for the year ended
Conference Call and Webcast
Centennial will host an investor conference call on
About
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 asSaudi Arabia , and other oil and natural gas producing countries, such asRussia , 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;
- political and economic conditions in or affecting other producing regions or countries, including the
Middle East ,Russia ,Eastern Europe ,Africa andSouth America ; - our business strategy and future drilling plans;
- our reserves and our ability to replace the reserves we produce through drilling and property acquisitions;
- our drilling prospects, inventories, projects and programs;
- our financial strategy, liquidity and capital required for our development program;
- our realized oil, natural gas and NGL prices;
- the timing and amount of our future production of oil, natural gas and NGLs;
- our hedging strategy and results;
- our competition and government regulations;
- our ability to obtain permits and governmental approvals;
- our pending legal or environmental matters;
- the marketing and transportation of our oil, natural gas and NGLs;
- our leasehold or business acquisitions;
- costs 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;
- 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
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, also referred to as “leverage” in this press release, 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 twelve month periods ended
Contact:
Sr. Director, Investor Relations
(832) 240-3265
ir@cdevinc.com
Details of our 2022 operational and financial guidance are presented below:
2022 FY Guidance | |||
Net average daily production (Boe/d) | 61,500 | — | 67,500 |
Net average daily oil production (Bbls/d) | 33,500 | — | 36,500 |
Production costs | |||
Lease operating expenses ($/Boe) | — | ||
Gathering, processing and transportation expenses ($/Boe) | — | ||
Depreciation, depletion, and amortization ($/Boe) | — | ||
Cash general and administrative ($/Boe)1 | — | ||
Stock-based compensation ($/Boe)2 | — | ||
Severance and ad valorem taxes (% of revenue) | 6.0% | — | 8.0% |
Capital expenditure program ($MM) | $365 | — | $425 |
Drilling, completion and facilities | — | ||
Infrastructure, land and other | — | ||
Operated drilling program | |||
Wells spud (gross) | 47 | — | 53 |
Wells completed (gross) | 47 | — | 53 |
Average working interest | ~85% | ||
Average lateral length (feet) | ~8,750 |
(1) Cash general and administrative guidance does not include the portion of stock-based compensation that will settle in cash.
(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 the cash-based liability 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 future stock price and, for certain awards, with changes in Centennial’s future stock price performance versus a defined peer group of companies.
Operating Highlights
Three Months Ended |
Year Ended |
||||||||||||||
2021 |
2020 |
2021 |
2020 |
||||||||||||
Net revenues (in thousands): | |||||||||||||||
Oil sales | $ | 230,791 | $ | 112,123 | $ | 743,069 | $ | 475,694 | |||||||
Natural gas sales | 43,212 | 17,724 | 149,478 | 46,776 | |||||||||||
NGL sales | 42,416 | 18,230 | 137,345 | 57,986 | |||||||||||
Oil and gas sales | $ | 316,419 | $ | 148,077 | $ | 1,029,892 | $ | 580,456 | |||||||
Average sales price: | |||||||||||||||
Oil (per Bbl) | $ | 72.78 | $ | 40.36 | $ | 63.50 | $ | 36.02 | |||||||
Effect of derivative settlements on average price (per Bbl) | (10.36 | ) | (1.54 | ) | (10.19 | ) | (3.15 | ) | |||||||
Oil net of hedging (per Bbl) | $ | 62.42 | $ | 38.82 | $ | 53.31 | $ | 32.87 | |||||||
Average NYMEX price for oil (per Bbl) | $ | 77.09 | $ | 42.66 | $ | 67.89 | $ | 39.44 | |||||||
Oil differential from NYMEX | (4.31 | ) | (2.30 | ) | (4.39 | ) | (3.42 | ) | |||||||
Natural gas (per Mcf) | $ | 4.41 | $ | 1.76 | $ | 3.67 | $ | 1.13 | |||||||
Effect of derivative settlements on average price (per Mcf) | (1.03 | ) | (0.09 | ) | (0.32 | ) | (0.12 | ) | |||||||
Natural gas net of hedging (per Mcf) | $ | 3.38 | $ | 1.67 | $ | 3.35 | $ | 1.01 | |||||||
Average NYMEX price for natural gas (per Mcf) | $ | 4.74 | $ | 2.47 | $ | 3.84 | $ | 1.99 | |||||||
Natural gas differential from NYMEX | (0.33 | ) | (0.71 | ) | (0.17 | ) | (0.86 | ) | |||||||
NGL (per Bbl) | $ | 44.28 | $ | 17.65 | $ | 36.61 | $ | 12.91 | |||||||
Net production: | |||||||||||||||
Oil (MBbls) | 3,170 | 2,778 | 11,701 | 13,207 | |||||||||||
Natural gas (MMcf) | 9,808 | 10,093 | 40,741 | 41,302 | |||||||||||
NGL (MBbls) | 958 | 1,032 | 3,752 | 4,490 | |||||||||||
Total (MBoe)(1) | 5,764 | 5,493 | 22,243 | 24,581 | |||||||||||
Average daily net production: | |||||||||||||||
Oil (Bbls/d) | 34,468 | 30,196 | 32,058 | 36,084 | |||||||||||
Natural gas (Mcf/d) | 106,613 | 109,712 | 111,619 | 112,848 | |||||||||||
NGL (Bbls/d) | 10,412 | 11,226 | 10,278 | 12,269 | |||||||||||
Total (Boe/d)(1) | 62,649 | 59,708 | 60,939 | 67,161 |
_________________________
(1) Calculated by converting natural gas to oil equivalent barrels at a ratio of six Mcf of natural gas to one Boe.
Operating Expenses
Three Months Ended |
Year Ended |
||||||||||||||
2021 |
2020 |
2021 |
2020 |
||||||||||||
Operating costs (in thousands): | |||||||||||||||
Lease operating expenses | $ | 28,897 | $ | 26,261 | $ | 106,419 | $ | 109,282 | |||||||
Severance and ad valorem taxes | 20,973 | 9,309 | 67,140 | 39,417 | |||||||||||
Gathering, processing, and transportation expense | 21,613 | 17,956 | 85,896 | 71,309 | |||||||||||
Operating cost metrics: | |||||||||||||||
Lease operating expenses (per Boe) | $ | 5.01 | $ | 4.78 | $ | 4.78 | $ | 4.45 | |||||||
Severance and ad valorem taxes (% of revenue) | 6.6 | % | 6.3 | % | 6.5 | % | 6.8 | % | |||||||
Gathering, processing, and transportation expense (per Boe) | 3.75 | 3.27 | 3.86 | 2.90 |
Consolidated Statements of Operations
(in thousands, except per share data)
Three Months Ended |
Year Ended |
||||||||||||||
2021 |
2020 |
2021 |
2020 |
||||||||||||
Operating revenues | |||||||||||||||
Oil and gas sales | $ | 316,419 | $ | 148,077 | $ | 1,029,892 | $ | 580,456 | |||||||
Operating expenses | |||||||||||||||
Lease operating expenses | 28,897 | 26,261 | 106,419 | 109,282 | |||||||||||
Severance and ad valorem taxes | 20,973 | 9,309 | 67,140 | 39,417 | |||||||||||
Gathering, processing and transportation expenses | 21,613 | 17,956 | 85,896 | 71,309 | |||||||||||
Depreciation, depletion and amortization | 75,863 | 74,832 | 289,122 | 358,554 | |||||||||||
Impairment and abandonment expense | 6,400 | 40,561 | 32,511 | 691,190 | |||||||||||
Exploration and other expenses | 3,185 | 7,625 | 7,883 | 18,355 | |||||||||||
General and administrative expenses | 20,643 | 18,421 | 110,454 | 72,867 | |||||||||||
Total operating expenses | 177,574 | 194,965 | 699,425 | 1,360,974 | |||||||||||
Net gain (loss) on sale of long-lived assets | 34,422 | 10 | 34,168 | 398 | |||||||||||
Proceeds from terminated sale of assets | — | — | 5,983 | — | |||||||||||
Income (loss) from operations | 173,267 | (46,878 | ) | 370,618 | (780,120 | ) | |||||||||
Other income (expense) | |||||||||||||||
Interest expense | (13,931 | ) | (17,682 | ) | (61,288 | ) | (69,192 | ) | |||||||
Gain (loss) on extinguishment of debt | — | — | (22,156 | ) | 143,443 | ||||||||||
Net gain (loss) on derivative instruments | 1,860 | (24,205 | ) | (148,825 | ) | (64,535 | ) | ||||||||
Other income (expense) | 124 | 110 | 395 | 81 | |||||||||||
Total other income (expense) | (11,947 | ) | (41,777 | ) | (231,874 | ) | 9,797 | ||||||||
Income (loss) before income taxes | 161,320 | (88,655 | ) | 138,744 | (770,323 | ) | |||||||||
Income tax (expense) benefit | (569 | ) | — | (569 | ) | 85,124 | |||||||||
Net income (loss) | 160,751 | (88,655 | ) | 138,175 | (685,199 | ) | |||||||||
Less: Net (income) loss attributable to noncontrolling interest | — | — | — | 2,362 | |||||||||||
Net income (loss) attributable to Class A Common Stock | $ | 160,751 | $ | (88,655 | ) | $ | 138,175 | $ | (682,837 | ) | |||||
Income (loss) per share of Class A Common Stock: | |||||||||||||||
Basic | $ | 0.57 | $ | (0.32 | ) | $ | 0.49 | $ | (2.46 | ) | |||||
Diluted | $ | 0.51 | $ | (0.32 | ) | $ | 0.46 | $ | (2.46 | ) |
Consolidated Balance Sheets
(in thousands, except share and per share amounts)
ASSETS | |||||||
Current assets | |||||||
Cash and cash equivalents | $ | 9,380 | $ | 5,800 | |||
Accounts receivable, net | 71,295 | 54,557 | |||||
Prepaid and other current assets | 5,860 | 5,229 | |||||
Total current assets | 86,535 | 65,586 | |||||
Property and Equipment | |||||||
Oil and natural gas properties, successful efforts method | |||||||
Unproved properties | 1,040,386 | 1,209,205 | |||||
Proved properties | 4,623,726 | 4,395,473 | |||||
Accumulated depreciation, depletion and amortization | (1,989,489 | ) | (1,877,832 | ) | |||
Total oil and natural gas properties, net | 3,674,623 | 3,726,846 | |||||
Other property and equipment, net | 11,197 | 12,650 | |||||
Total property and equipment, net | 3,685,820 | 3,739,496 | |||||
Noncurrent assets | |||||||
Operating lease right-of-use assets | 16,385 | 3,176 | |||||
Other noncurrent assets | 15,854 | 19,167 | |||||
TOTAL ASSETS | $ | 3,804,594 | $ | 3,827,425 | |||
LIABILITIES AND EQUITY | |||||||
Current liabilities | |||||||
Accounts payable and accrued expenses | $ | 130,256 | $ | 110,439 | |||
Operating lease liabilities | 1,413 | 3,155 | |||||
Other current liabilities | 36,230 | 18,274 | |||||
Total current liabilities | 167,899 | 131,868 | |||||
Noncurrent liabilities | |||||||
Long-term debt, net | 825,565 | 1,068,624 | |||||
Asset retirement obligations | 17,240 | 17,009 | |||||
Deferred income taxes | 2,589 | 2,589 | |||||
Operating lease liabilities | 16,002 | 422 | |||||
Other noncurrent liabilities | 24,579 | 2,952 | |||||
Total liabilities | 1,053,874 | 1,223,464 | |||||
Shareholders’ equity | |||||||
Common stock, |
|||||||
Class A: 294,260,623 shares issued and 284,696,972 shares outstanding at |
29 | 29 | |||||
Additional paid-in capital | 3,013,017 | 3,004,433 | |||||
Retained earnings (accumulated deficit) | (262,326 | ) | (400,501 | ) | |||
Total shareholders’ equity | 2,750,720 | 2,603,961 | |||||
Noncontrolling interest | — | — | |||||
Total equity | 2,750,720 | 2,603,961 | |||||
TOTAL LIABILITIES AND EQUITY | $ | 3,804,594 | $ | 3,827,425 |
Consolidated Statements of Cash Flows
(in thousands)
Year Ended |
|||||||
2021 | 2020 | ||||||
Cash flows from operating activities: | |||||||
Net income (loss) | $ | 138,175 | $ | (685,199 | ) | ||
Adjustments to reconcile net income (loss) to net cash provided by operating activities: | |||||||
Depreciation, depletion and amortization | 289,122 | 358,554 | |||||
Stock-based compensation expense - equity awards | 37,541 | 20,966 | |||||
Stock-based compensation expense - liability awards | 20,573 | 3,602 | |||||
Impairment and abandonment expense | 32,511 | 691,190 | |||||
Exploratory dry hole costs | — | 6,615 | |||||
Deferred tax expense (benefit) | 569 | (85,124 | ) | ||||
Net (gain) loss on sale of long-lived assets | (34,168 | ) | (398 | ) | |||
Non-cash portion of derivative (gain) loss | 16,700 | 17,884 | |||||
Amortization of debt issuance costs and debt discount | 4,992 | 5,923 | |||||
(Gain) loss on extinguishment of debt | 22,156 | (143,443 | ) | ||||
Changes in operating assets and liabilities: | |||||||
(Increase) decrease in accounts receivable | (21,475 | ) | 44,572 | ||||
(Increase) decrease in prepaid and other assets | 2,907 | (3,804 | ) | ||||
Increase (decrease) in accounts payable and other liabilities | 16,016 | (59,962 | ) | ||||
Net cash provided by operating activities | 525,619 | 171,376 | |||||
Cash flows from investing activities: | |||||||
Acquisition of oil and natural gas properties | (6,510 | ) | (8,464 | ) | |||
Drilling and development capital expenditures | (319,640 | ) | (318,465 | ) | |||
Purchases of other property and equipment | (901 | ) | (1,083 | ) | |||
Proceeds from sales of oil and natural gas properties | 100,575 | 1,689 | |||||
Net cash used in investing activities | (226,476 | ) | (326,323 | ) | |||
Cash flows from financing activities: | |||||||
Proceeds from borrowings under revolving credit facility | 570,000 | 570,000 | |||||
Repayment of borrowings under revolving credit facility | (875,000 | ) | (415,000 | ) | |||
Proceeds from issuance of senior notes | 170,000 | — | |||||
Debt exchange and 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 | 132 | — | |||||
Restricted stock used for tax withholdings | (14,497 | ) | (607 | ) | |||
Net cash (used in) provided by financing activities | (297,547 | ) | 147,743 | ||||
Net increase (decrease) in cash, cash equivalents and restricted cash | 1,596 | (7,204 | ) | ||||
Cash, cash equivalents and restricted cash, beginning of period | 8,339 | 15,543 | |||||
Cash, cash equivalents and restricted cash, end of period | $ | 9,935 | $ | 8,339 |
Reconciliation of cash, cash equivalents and restricted cash presented on the consolidated statements of cash flows for the periods presented:
Year Ended |
|||||
2021 | 2020 | ||||
Cash and cash equivalents | $ | 9,380 | $ | 5,800 | |
Restricted cash | $ | 555 | $ | 2,539 | |
Total cash, cash equivalents and restricted cash | $ | 9,935 | $ | 8,339 |
Non-GAAP Financial Measures
In addition to disclosing financial results calculated in accordance with
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 expense, 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 |
Year Ended |
||||||||||||||
(in thousands) | 2021 | 2020 | 2021 | 2020 | |||||||||||
Adjusted EBITDAX reconciliation to net income: | |||||||||||||||
Net income (loss) attributable to Class A Common Stock | $ | 160,751 | $ | (88,655 | ) | $ | 138,175 | $ | (682,837 | ) | |||||
Net income (loss) attributable to noncontrolling interest | — | — | — | (2,362 | ) | ||||||||||
Interest expense | 13,931 | 17,682 | 61,288 | 69,192 | |||||||||||
Income tax expense (benefit) | 569 | — | 569 | (85,124 | ) | ||||||||||
Depreciation, depletion and amortization | 75,863 | 74,832 | 289,122 | 358,554 | |||||||||||
Impairment and abandonment expense | 6,400 | 40,561 | 32,511 | 691,190 | |||||||||||
(Gain) loss on extinguishment of debt | — | — | 22,156 | (143,443 | ) | ||||||||||
Non-cash derivative (gain) loss | (44,790 | ) | 18,987 | 16,700 | 17,884 | ||||||||||
Stock-based compensation expense(1) | 5,594 | 8,111 | 56,320 | 23,045 | |||||||||||
Exploration and other expenses | 3,185 | 7,625 | 7,883 | 18,355 | |||||||||||
Workforce reduction severance payments | — | — | — | 3,466 | |||||||||||
Transaction costs | — | — | — | 476 | |||||||||||
(Gain) loss on sale of long-lived assets | (34,422 | ) | (10 | ) | (34,168 | ) | (398 | ) | |||||||
Proceeds from terminated sale of assets | — | — | (5,983 | ) | — | ||||||||||
Adjusted EBITDAX | $ | 187,081 | $ | 79,133 | $ | 584,573 | $ | 267,998 |
(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 (Deficit)
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 |
Year Ended |
||||||||||||||
(in thousands) | 2021 |
2020 |
2021 |
2020 |
|||||||||||
Net cash provided by operating activities | $ | 192,487 | $ | 41,144 | $ | 525,619 | $ | 171,376 | |||||||
Changes in working capital: | |||||||||||||||
Accounts receivable | (21,523 | ) | 3,567 | 21,475 | (44,572 | ) | |||||||||
Prepaid and other assets | (1,104 | ) | 979 | (2,907 | ) | 3,804 | |||||||||
Accounts payable and other liabilities | 1,433 | 16,855 | (16,016 | ) | 59,962 | ||||||||||
Discretionary cash flow | 171,293 | 62,545 | 528,171 | 190,570 | |||||||||||
Less: total capital expenditures incurred | (86,500 | ) | (29,900 | ) | (321,500 | ) | (254,800 | ) | |||||||
Free cash flow (deficit) | $ | 84,793 | $ | 32,645 | $ | 206,671 | $ | (64,230 | ) |
The following table summarizes the approximate volumes and average contract prices of the hedge contracts the Company had in place as of
Period | Volume (Bbls) |
Volume (Bbls/d) |
Wtd. Avg. Crude Price ($/Bbl)(1) |
||||
Crude oil swaps | 1,080,000 | 12,000 | |||||
1,092,000 | 12,000 | 65.28 | |||||
782,000 | 8,500 | 65.46 | |||||
690,000 | 7,500 | 65.63 | |||||
225,000 | 2,500 | 73.51 | |||||
227,500 | 2,500 | 73.25 | |||||
92,000 | 1,000 | 72.98 | |||||
92,000 | 1,000 | 72.98 | |||||
Period | Volume (Bbls) |
Volume (Bbls/d) |
Wtd. Avg. Collar Price Ranges ($/Bbl)(2) |
||||
Crude oil collars | 225,000 | 2,500 | |||||
227,500 | 2,500 | 63.20 - 72.41 | |||||
184,000 | 2,000 | 75.00 - 89.05 | |||||
184,000 | 2,000 | 75.00 - 89.05 | |||||
225,000 | 2,500 | 70.00 - 81.36 | |||||
227,500 | 2,500 | 70.00 - 81.36 | |||||
138,000 | 1,500 | 70.00 - 80.17 | |||||
138,000 | 1,500 | 70.00 - 80.17 | |||||
Period | Volume (Bbls) |
Volume (Bbls/d) |
Wtd. Avg. Differential ($/Bbl)(3) |
||||
Crude oil basis differential swaps | 538,500 | 5,983 | |||||
591,500 | 6,500 | 0.32 | |||||
552,000 | 6,000 | 0.29 | |||||
552,000 | 6,000 | 0.29 | |||||
Period | Volume (Bbls) |
Volume (Bbls/d) |
Wtd. Avg. Differential ($/Bbl)(4) |
||||
Crude oil roll differential swaps | 900,000 | 10,000 | |||||
910,000 | 10,000 | 0.71 | |||||
920,000 | 10,000 | 0.71 | |||||
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
(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 ($/MMBtu)(1) |
||||
Natural gas swaps | 2,700,000 | 30,000 | |||||
2,730,000 | 30,000 | 3.24 | |||||
2,760,000 | 30,000 | 3.24 | |||||
1,540,000 | 16,739 | 3.15 | |||||
Period | Volume (MMBtu) |
Volume (MMBtu/d) |
Wtd. Avg. Collar Price Ranges ($/MMBtu)(2) |
||||
Natural gas collars | 1,800,000 | 20,000 | |||||
1,820,000 | 20,000 | 3.50 - 3.97 | |||||
1,840,000 | 20,000 | 3.50 - 3.97 | |||||
2,450,000 | 26,630 | 3.87 - 5.06 | |||||
2,700,000 | 30,000 | 4.00 - 5.42 | |||||
910,000 | 10,000 | 3.00 - 4.09 | |||||
920,000 | 10,000 | 3.00 - 4.09 | |||||
920,000 | 10,000 | 3.17 - 4.74 | |||||
910,000 | 10,000 | 3.25 - 5.06 | |||||
Period | Volume (MMBtu) |
Volume (MMBtu/d) |
Wtd. Avg. Differential ($/MMBtu)(3) |
||||
Natural gas basis differential swaps | 4,500,000 | 50,000 | |||||
1,820,000 | 20,000 | (0.45) | |||||
1,840,000 | 20,000 | (0.45) | |||||
1,840,000 | 20,000 | (0.45) | |||||
1,350,000 | 15,000 | (0.85) | |||||
1,365,000 | 15,000 | (0.85) | |||||
1,380,000 | 15,000 | (0.85) | |||||
1,380,000 | 15,000 | (0.85) |
________________________
(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 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.
(3) 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.
The following table summarizes estimated proved reserves, pre-tax PV 10%, and standardized measure of discounted future cash flows for the periods indicated:
Proved developed reserves: | |||||||||||
Oil (MBbls) | 77,973 | 70,716 | 74,842 | ||||||||
Natural gas (MMcf) | 326,223 | 279,556 | 237,791 | ||||||||
NGL (MBbls) | 30,318 | 31,672 | 32,743 | ||||||||
Total proved developed reserves (MBoe)(1) | 162,662 | 148,981 | 147,216 | ||||||||
Proved undeveloped reserves: | |||||||||||
Oil (MBbls) | 75,480 | 79,776 | 75,317 | ||||||||
Natural gas (MMcf) | 250,782 | 248,231 | 264,639 | ||||||||
NGL (MBbls) | 25,265 | 28,773 | 34,499 | ||||||||
Total proved undeveloped reserves (MBoe)(1) | 142,542 | 149,921 | 153,923 | ||||||||
Total proved reserves: | |||||||||||
Oil (MBbls) | 153,453 | 150,492 | 150,159 | ||||||||
Natural gas (MMcf) | 577,005 | 527,787 | 502,430 | ||||||||
NGL (MBbls) | 55,583 | 60,445 | 67,242 | ||||||||
Total proved reserves (MBoe)(1) | 305,204 | 298,902 | 301,139 | ||||||||
Proved developed reserves % | 53 | % | 50 | % | 49 | % | |||||
Proved undeveloped reserves % | 47 | % | 50 | % | 51 | % | |||||
Reserve values (in millions): | |||||||||||
Standard measure of discounted future net cash flows | $ | 3,396.3 | $ | 1,184.7 | $ | 2,062.4 | |||||
Discounted future income tax expense | 481.2 | 4.4 | 135.5 | ||||||||
Total proved pre-tax PV 10%(2) | $ | 3,877.5 | $ | 1,189.1 | $ | 2,197.9 |
_______________________
(1) Calculated by converting natural gas to oil equivalent barrels at a ratio of six Mcf of natural gas to one Boe.
(2) Total proved pre-tax PV 10% (“Pre-tax PV 10%”) 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, and it is derived from the standardized measure of discounted future net cash flows (the ‘‘Standardized Measure’’), which is the most directly comparable GAAP financial measure. Pre-tax PV 10% is computed on the same basis as the Standardized Measure but without deducting future income taxes. We believe Pre-tax PV 10% is a useful measure for investors when evaluating the relative monetary significance of our oil and natural gas properties. We further believe investors may utilize our Pre-tax PV 10% as a basis for comparison of the relative size and value of our proved reserves to other companies because many factors that are unique to each individual company impact the amount of future income taxes to be paid. Our management uses this measure when assessing the potential return on investment related to our oil and gas properties and acquisitions. However, Pre-tax PV 10% is not a substitute for the Standardized Measure. Our Pre-tax PV 10% and Standardized Measure do not purport to present the fair value of our proved oil, NGL and natural gas reserves.
Supplemental Measures
Organic Reserve Replacement Ratio
The Company uses the organic reserve replacement ratio as an indicator of the Company’s ability to replace the reserves that it has developed and to increase its reserves over time. The ratio is not a representation of value creation and has a number of limitations that should be considered. For example, the ratio does not incorporate the costs or timing of developing future reserves. The organic reserve replacement ratio of 149% is calculated as (a) our total 2021 proved reserve extensions and discoveries and revisions to previous estimates of 33.1 MMBoe divided by (b) the Company’s total 2021 production of 22.2 MMBoe. The ratio calculation excludes acquisitions and divestitures.
Proved Developed and Drill-Bit Finding and Development (“F&D”) Costs
The Company uses proved developed F&D cost and drill-bit F&D cost as indicators of capital efficiency, in that they measure the Company’s costs to add proved reserves on a per Boe basis. Both calculations exclude acquisitions and divestitures and are subject to limitations, including the uncertainty of future costs to develop the Company’s reserves.
Proved developed F&D of
Drill-bit F&D of

Source: Centennial Resource Development