Centennial Resource Development Announces First Quarter 2022 Results
DENVER, May 4, 2022 (GLOBE NEWSWIRE) -- Centennial Resource Development, Inc. (“Centennial” or the “Company”) (NASDAQ: CDEV) today announced first quarter 2022 financial and operational results.
First Quarter Financial and Operational Highlights
•Generated record free cash flow1 of $89 million
•Fully repaid all borrowings under the credit facility
•Delivered strong well results
•Reduced leverage1 for the fourth consecutive quarter
•Continued to drive operational efficiencies
Financial Results
For the first quarter, Centennial generated net cash from operating activities of $160.1 million and free cash flow of $88.8 million. The Company reported net income during the quarter of $15.8 million, or $0.05 per diluted share, compared to a net loss of $34.6 million, or $(0.12) per diluted share, in the prior year period.
Average daily crude oil production for the first quarter was 32,741 barrels of oil per day (“Bbls/d”) compared to 28,239 Bbls/d in the prior year period. Total equivalent production during the quarter averaged 61,359 barrels of oil equivalent per day (“Boe/d”) compared to 54,202 Boe/d in the prior year period.
“During the first quarter, Centennial generated strong well results across both the Northern and Southern Delaware Basin while continuing to drive additional operational efficiencies. This execution, coupled with supportive commodity prices, enabled us to achieve record free cash flow and reduce leverage during the quarter,” said Sean R. Smith, Chief Executive Officer. “We are well-positioned to deliver on our key 2022 objectives of generating strong production growth, further strengthening our balance sheet and initiating our share repurchase program.”
First Quarter Operational Results
Through larger well packages and extended laterals, Centennial continues to efficiently develop its Delaware Basin acreage position. During the quarter, the Company completed eighteen wells through four separate developments, including two six-well developments. Located on the southern portion of the Company’s Miramar acreage in Reeves County, Texas, the Powdered Donut State (average 93% working interest (“WI”)) four-well development was drilled in the Third Bone Spring Sand (1), Wolfcamp A (1) and Wolfcamp C (2) intervals with average 9,800-foot laterals. The wells delivered an average 30-day initial production (“IP”) rate of 2,411 Boe/d (42% oil) per well. Notably, the maximum IP-24 hour rate for the four-well pad was over 41 MMcf of natural gas.
In Lea County, New Mexico, the Chimichangas and Queso Blanco (average 75% WI) six-well development was drilled in the Second Bone Spring Sand interval with average 8,400-foot laterals. The wells delivered an average 30-day IP rate of 2,160 Boe/d (82% oil) per well and averaged 212 Bbls/d of oil per 1,000 foot of lateral per well.
Also in Lea County, the Pac-Man and Donkey Kong (average 93% WI) wells represent another six-well development, drilled using a stacked-staggered pattern in the upper and lower portions of the Second Bond Spring Sand interval with 8,500-foot average lateral lengths. The wells averaged 1,749 Boe/d, or 1,433 Bbls/d of oil, per well for the 30-day IP period.
“First quarter well performance highlights the quality of Centennial’s portfolio across the Delaware Basin. The higher natural gas and NGL mix on our Texas asset provides enhanced economics at current prices. In New Mexico, our successful execution of larger scale development targeting the Bone Spring Sand interval continues to produce strong returns,” said Smith. “As a result, we expect our average completed well during the quarter to pay-out in approximately four months, assuming strip pricing.”
Smith continued, “Additionally, our field personnel have done an excellent job navigating the challenging oilfield service environment. We have experienced no operational delays or cost overruns year-to-date. Going forward, we will continue our focus on developing larger well packages and driving further efficiencies in an effort to partially offset future cost inflation.”
Total capital expenditures (“capex”) incurred for the quarter were $114.7 million, inclusive of $111.6 million in drilling, completion and facilities costs with an additional $3.1 million spent on infrastructure, land and other.
“Building on the efficiencies gained last year, our operations team increased completed stages per day by 14% compared to the prior quarter. As a result, we completed six more wells than anticipated during the quarter while still delivering capex in-line with our expectations,” said Smith. “With over half of our first quarter completions brought online during March, we expect to generate significant oil production growth next quarter.”
Capital Structure and Liquidity
During the first quarter, Centennial repaid all of the outstanding borrowings under its $750 million revolving credit facility and had $51 million in cash on its balance sheet at March 31, 2022. Total net debt and total debt at the end of the quarter were $765 million and $816 million, respectively. Net debt-to-LTM EBITDAX at March 31, 2022 was 1.1x compared to 1.4x at December 31, 2021.
Hedge Position Update
For the remaining three quarters of 2022, Centennial has a total of 12,489 Bbls/d of oil hedged, consisting of approximately 75% fixed price swaps with the remainder in costless collars. The Company has 15,500 Bbls/d of oil hedged for the second quarter of 2022 and 11,000 Bbls/d of oil hedged for the second half of 2022.
In recent months, Centennial has added to its 2023 crude oil hedge position. For the full year 2023, the Company has a total of 5,736 Bbls/d of oil hedged, consisting of approximately 70% costless collars. The Company currently has 3,992 Bbls/d of WTI oil collars in place with a weighted average floor and ceiling price of $73.13 per barrel and $85.67 per barrel, respectively. Also for 2023, the Company has 1,744 Bbls/d of WTI oil hedged at a fixed price of $73.26 per barrel.
In addition to the hedge positions discussed above, Centennial has certain other 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 April 30, 2022, 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 March 31, 2022, which is expected to be filed with the U.S. Securities and Exchange Commission (“SEC”) on May 5, 2022.
Conference Call and Webcast
Centennial will host an investor conference call on Thursday, May 5, 2022 at 8:00 a.m. Mountain (10:00 a.m. Eastern) to discuss first quarter 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: 3033538) 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: 3033538) 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;
•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 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 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 and Net Debt-to-LTM EBITDAX, also referred to as "leverage" in this press release, are non-GAAP financial measures. See “Non-GAAP Financial Measures” included within the Appendix of this press release for related disclosures and reconciliations to the most directly comparable financial measures calculated and presented in accordance with GAAP.
Contact:
Hays Mabry
Sr. Director, Investor Relations
(832) 240-3265
SOURCE Centennial Resource Development, Inc.
Centennial Resource Development, Inc.
Operating Highlights
| Three Months Ended March 31, | |||||||||||
| 2022 | 2021 | ||||||||||
| Net revenues (in thousands): | |||||||||||
| Oil sales | $ | 262,767 | $ | 133,726 | |||||||
| Natural gas sales | 39,018 | 35,451 | |||||||||
| NGL sales | 45,492 | 23,214 | |||||||||
| Oil and gas sales | $ | 347,277 | $ | 192,391 | |||||||
| Average sales prices: | |||||||||||
| Oil (per Bbl) | $ | 89.17 | $ | 52.62 | |||||||
| Effect of derivative settlements on average price (per Bbl) | (12.82) | (9.43) | |||||||||
| Oil net of hedging (per Bbl) | $ | 76.35 | $ | 43.19 | |||||||
| Average NYMEX price for oil (per Bbl) | $ | 94.40 | $ | 57.84 | |||||||
| Oil differential from NYMEX | (5.23) | (5.22) | |||||||||
| Natural gas (per Mcf) | $ | 3.93 | $ | 3.79 | |||||||
| Effect of derivative settlements on average price (per Mcf) | (0.51) | 0.12 | |||||||||
| Natural gas net of hedging (per Mcf) | $ | 3.42 | $ | 3.91 | |||||||
| Average NYMEX price for natural gas (per Mcf) | $ | 4.60 | $ | 3.44 | |||||||
| Natural gas differential from NYMEX | (0.67) | 0.35 | |||||||||
| NGL (per Bbl) | $ | 49.37 | $ | 29.78 | |||||||
| Net production: | |||||||||||
| Oil (MBbls) | 2,947 | 2,542 | |||||||||
| Natural gas (MMcf) | 9,925 | 9,343 | |||||||||
| NGL (MBbls) | 921 | 780 | |||||||||
Total (MBoe)(1) | 5,522 | 4,878 | |||||||||
| Average daily net production: | |||||||||||
| Oil (Bbls/d) | 32,741 | 28,239 | |||||||||
| Natural gas (Mcf/d) | 110,280 | 103,806 | |||||||||
| NGL (Bbls/d) | 10,238 | 8,662 | |||||||||
Total (Boe/d)(1) | 61,359 | 54,202 | |||||||||
(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 March 31, | |||||||||||
| 2022 | 2021 | ||||||||||
| Operating costs (in thousands): | |||||||||||
| Lease operating expenses | $ | 28,734 | $ | 25,861 | |||||||
| Severance and ad valorem taxes | 25,051 | 12,583 | |||||||||
| Gathering, processing and transportation expenses | 21,891 | 20,625 | |||||||||
| Operating cost metrics: | |||||||||||
| Lease operating expenses (per Boe) | $ | 5.20 | $ | 5.30 | |||||||
| Severance and ad valorem taxes (% of revenue) | 7.2 | % | 6.5 | % | |||||||
| Gathering, processing and transportation expenses (per Boe) | $ | 3.96 | $ | 4.23 | |||||||
Centennial Resource Development, Inc.
Consolidated Statements of Operations (unaudited)
(in thousands, except per share data)
| Three Months Ended March 31, | |||||||||||
| 2022 | 2021 | ||||||||||
| Operating revenues | |||||||||||
| Oil and gas sales | $ | 347,277 | $ | 192,391 | |||||||
| Operating expenses | |||||||||||
| Lease operating expenses | 28,734 | 25,861 | |||||||||
| Severance and ad valorem taxes | 25,051 | 12,583 | |||||||||
Gathering, processing and transportation expenses | 21,891 | 20,625 | |||||||||
| Depreciation, depletion and amortization | 71,009 | 63,783 | |||||||||
| General and administrative expenses | 30,603 | 25,256 | |||||||||
| Impairment and abandonment expense | 2,627 | 9,200 | |||||||||
| Exploration and other expenses | 2,307 | 1,095 | |||||||||
| Total operating expenses | 182,222 | 158,403 | |||||||||
| Net gain (loss) on sale of long-lived assets | 82 | 44 | |||||||||
| Income (loss) from operations | 165,137 | 34,032 | |||||||||
| Other income (expense) | |||||||||||
| Interest expense | (13,154) | (17,485) | |||||||||
| Net gain (loss) on derivative instruments | (129,523) | (51,199) | |||||||||
| Other income (expense) | 118 | 7 | |||||||||
Total other income (expense) | (142,559) | (68,677) | |||||||||
| Income (loss) before income taxes | 22,578 | (34,645) | |||||||||
| Income tax (expense) benefit | (6,776) | — | |||||||||
| Net income (loss) | $ | 15,802 | $ | (34,645) | |||||||
| Income (loss) per share of Common Stock: | |||||||||||
| Basic | $ | 0.06 | $ | (0.12) | |||||||
| Diluted | $ | 0.05 | $ | (0.12) | |||||||
Centennial Resource Development, Inc.
Consolidated Balance Sheets (unaudited)
(in thousands, except share and per share amounts)
| March 31, 2022 | December 31, 2021 | ||||||||||
| ASSETS | |||||||||||
| Current assets | |||||||||||
| Cash and cash equivalents | $ | 50,624 | $ | 9,380 | |||||||
| Accounts receivable, net | 131,837 | 71,295 | |||||||||
| Prepaid and other current assets | 6,973 | 5,860 | |||||||||
| Total current assets | 189,434 | 86,535 | |||||||||
| Property and Equipment | |||||||||||
| Oil and natural gas properties, successful efforts method | |||||||||||
| Unproved properties | 1,032,096 | 1,040,386 | |||||||||
| Proved properties | 4,742,872 | 4,623,726 | |||||||||
| Accumulated depreciation, depletion and amortization | (2,059,679) | (1,989,489) | |||||||||
| Total oil and natural gas properties, net | 3,715,289 | 3,674,623 | |||||||||
| Other property and equipment, net | 11,774 | 11,197 | |||||||||
| Total property and equipment, net | 3,727,063 | 3,685,820 | |||||||||
| Noncurrent assets | |||||||||||
| Operating lease right-of-use assets | 14,714 | 16,385 | |||||||||
| Other noncurrent assets | 27,321 | 15,854 | |||||||||
| TOTAL ASSETS | $ | 3,958,532 | $ | 3,804,594 | |||||||
| LIABILITIES AND EQUITY | |||||||||||
| Current liabilities | |||||||||||
| Accounts payable and accrued expenses | $ | 178,940 | $ | 130,256 | |||||||
| Operating lease liabilities | 1,728 | 1,413 | |||||||||
| Derivative Instruments | 117,689 | 35,150 | |||||||||
| Other current liabilities | 1,370 | 1,080 | |||||||||
| Total current liabilities | 299,727 | 167,899 | |||||||||
| Noncurrent liabilities | |||||||||||
| Long-term debt, net | 801,203 | 825,565 | |||||||||
| Asset retirement obligations | 17,647 | 17,240 | |||||||||
| Deferred income taxes | 8,834 | 2,589 | |||||||||
| Operating lease liabilities | 14,473 | 16,002 | |||||||||
| Other noncurrent liabilities | 45,571 | 24,579 | |||||||||
| Total liabilities | 1,187,455 | 1,053,874 | |||||||||
Commitments and contingencies (Note 11) | |||||||||||
| Shareholders’ equity | |||||||||||
Common stock, $0.0001 par value, 620,000,000 shares authorized; 294,135,384 shares issued and 284,991,150 shares outstanding at March 31, 2022 and 294,260,623 shares issued and 284,696,972 shares outstanding at December 31, 2021 | 29 | 29 | |||||||||
| Additional paid-in capital | 3,017,572 | 3,013,017 | |||||||||
| Retained earnings (accumulated deficit) | (246,524) | (262,326) | |||||||||
| Total Shareholders' equity | 2,771,077 | 2,750,720 | |||||||||
| TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY | $ | 3,958,532 | $ | 3,804,594 | |||||||
Centennial Resource Development, Inc.
Consolidated Statements of Cash Flows (unaudited)
(in thousands)
| Three Months Ended March 31, | |||||||||||
| 2022 | 2021 | ||||||||||
| Cash flows from operating activities: | |||||||||||
| Net income (loss) | $ | 15,802 | $ | (34,645) | |||||||
| Adjustments to reconcile net income (loss) to net cash provided by operating activities: | |||||||||||
| Depreciation, depletion and amortization | 71,009 | 63,783 | |||||||||
| Stock-based compensation expense - equity awards | 5,545 | 4,585 | |||||||||
| Stock-based compensation expense - liability awards | 13,720 | 10,414 | |||||||||
| Impairment and abandonment expense | 2,627 | 9,200 | |||||||||
| Deferred tax expense (benefit) | 6,776 | — | |||||||||
| Net (gain) loss on sale of long-lived assets | (82) | (44) | |||||||||
| Non-cash portion of derivative (gain) loss | 86,645 | 28,313 | |||||||||
| Amortization of debt issuance costs and debt discount | 1,492 | 1,847 | |||||||||
| Changes in operating assets and liabilities: | |||||||||||
| (Increase) decrease in accounts receivable | (53,824) | (14,997) | |||||||||
| (Increase) decrease in prepaid and other assets | (415) | (264) | |||||||||
| Increase (decrease) in accounts payable and other liabilities | 10,825 | 4,154 | |||||||||
| Net cash provided by operating activities | 160,120 | 72,346 | |||||||||
| Cash flows from investing activities: | |||||||||||
| Acquisition of oil and natural gas properties | (1,928) | (433) | |||||||||
| Drilling and development capital expenditures | (81,156) | (46,152) | |||||||||
| Purchases of other property and equipment | (1,052) | (181) | |||||||||
| Proceeds from sales of oil and natural gas properties | 48 | 168 | |||||||||
| Net cash used in investing activities | (84,088) | (46,598) | |||||||||
| Cash flows from financing activities: | |||||||||||
| Proceeds from borrowings under revolving credit facility | 135,000 | 70,000 | |||||||||
| Repayment of borrowings under revolving credit facility | (160,000) | (240,000) | |||||||||
| Proceeds from issuance of convertible senior notes | — | 170,000 | |||||||||
| Debt issuance costs | (8,530) | (5,444) | |||||||||
| Premiums paid on capped call transactions | — | (14,688) | |||||||||
| Proceeds from exercise of stock options | 1 | — | |||||||||
| Restricted stock used for tax withholdings | (1,259) | (477) | |||||||||
| Net cash used in financing activities | (34,788) | (20,609) | |||||||||
| Net increase (decrease) in cash, cash equivalents and restricted cash | 41,244 | 5,139 | |||||||||
| Cash, cash equivalents and restricted cash, beginning of period | 9,935 | 8,339 | |||||||||
| Cash, cash equivalents and restricted cash, end of period | $ | 51,179 | $ | 13,478 | |||||||
Reconciliation of cash, cash equivalents and restricted cash presented on the Consolidated Statements of Cash Flows for the periods presented:
| Three Months Ended March 31, | |||||||||||
| 2022 | 2021 | ||||||||||
| Cash and cash equivalents | $ | 50,624 | $ | 10,936 | |||||||
| Restricted cash | 555 | 2,542 | |||||||||
| Total cash, cash equivalents and restricted cash | $ | 51,179 | $ | 13,478 | |||||||
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 expense, non-cash gains or losses on derivatives, stock-based compensation (not cash-settled), 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 | |||||||||||||||||||||||||||||
| (in thousands) | 3/31/2022 | 12/31/2021 | 9/30/2021 | 6/30/2021 | 3/31/2021 | ||||||||||||||||||||||||
Adjusted EBITDAX reconciliation to net income: | |||||||||||||||||||||||||||||
Net income (loss) | $ | 15,802 | $ | 160,751 | $ | 37,124 | $ | (25,055) | $ | (34,645) | |||||||||||||||||||
Interest expense | 13,154 | 13,931 | 14,690 | 15,182 | 17,485 | ||||||||||||||||||||||||
Income tax expense (benefit) | 6,776 | 569 | — | — | — | ||||||||||||||||||||||||
Depreciation, depletion and amortization | 71,009 | 75,863 | 76,047 | 73,429 | 63,783 | ||||||||||||||||||||||||
Impairment and abandonment expenses | 2,627 | 6,400 | 7,712 | 9,199 | 9,200 | ||||||||||||||||||||||||
| (Gain) loss on extinguishment of debt | — | — | — | 22,156 | — | ||||||||||||||||||||||||
Non-cash derivative (gain) loss | 86,645 | (44,790) | 15,731 | 17,446 | 28,313 | ||||||||||||||||||||||||
Stock-based compensation expense(1) | 18,834 | 5,594 | 17,421 | 18,681 | 14,624 | ||||||||||||||||||||||||
| Exploration and other expenses | 2,307 | 3,185 | 1,839 | 1,764 | 1,095 | ||||||||||||||||||||||||
(Gain) loss on sale of long-lived assets | (82) | (34,422) | 290 | 8 | (44) | ||||||||||||||||||||||||
| Proceeds from terminated sale of assets | — | — | — | (5,983) | — | ||||||||||||||||||||||||
Adjusted EBITDAX | $ | 217,072 | $ | 187,081 | $ | 170,854 | $ | 126,827 | $ | 99,811 | |||||||||||||||||||
(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.
Net Debt-to-LTM EBITDAX (Leverage)
Net debt-to-LTM EBITDAX, also referred to as “leverage" in this press release, is a non-GAAP financial measure. We define net debt as long-term debt, net, plus unamortized debt discount and debt issuance costs on our senior notes minus cash and cash equivalents.
We define net debt-to-LTM EBITDAX as net debt (defined above) divided by Adjusted EBITDAX (defined and reconciled in the section above) for the last twelve months. We refer to this metric to show trends that investors may find useful in understanding our ability to service our 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. The following table presents a reconciliation of net debt to long-term debt, net and the calculation of net debt-to-LTM EBITDAX for each period presented:
| (in thousands) | March 31, 2022 | December 31, 2021 | |||||||||
| Long-term debt, net | 801,203 | 825,565 | |||||||||
| Unamortized debt discount and debt issuance costs on senior notes | 14,596 | 15,234 | |||||||||
| Long-term debt | 815,799 | 840,799 | |||||||||
| Less: cash and cash equivalents | (50,624) | (9,380) | |||||||||
| Net debt (Non-GAAP) | 765,175 | 831,419 | |||||||||
LTM EBITDAX(1) | 701,834 | 584,573 | |||||||||
| Net debt-to-LTM EBITDAX | 1.1 | 1.4 | |||||||||
(1) Represents adjusted EBITDAX (defined and reconciled in the section above) for the preceding twelve month period ended.
We do 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, we cannot reconcile forecasted net debt-to-LTM EBITDAX to long-term debt, net, or net income without unreasonable effort.
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 March 31, | |||||||||||
| (in thousands) | 2022 | 2021 | |||||||||
| Net cash provided by operating activities | $ | 160,120 | $ | 72,346 | |||||||
| Changes in working capital: | |||||||||||
| Accounts receivable | 53,824 | 14,997 | |||||||||
| Prepaid and other assets | 415 | 264 | |||||||||
| Accounts payable and other liabilities | (10,825) | (4,154) | |||||||||
| Discretionary cash flow | 203,534 | 83,453 | |||||||||
| Less: total capital expenditures incurred | (114,700) | (72,900) | |||||||||
| Free cash flow | $ | 88,834 | $ | 10,553 | |||||||
We do not provide guidance on the items used to reconcile between forecasted free cash flow to forecasted net cash provided by operating activities due to the uncertainty regarding timing and estimates of certain items. Therefore, we cannot reconcile forecasted free cash flow to net cash provided by operating activities without unreasonable effort.
The following table summarizes the approximate volumes and average contract prices of the hedge contracts the Company had in place as of March 31, 2022 and additional contracts entered into through April 30, 2022:
| Period | Volume (Bbls) | Volume (Bbls/d) | Wtd. Avg. Crude Price ($/Bbl)(1) | ||||||||||||||||||||
| Crude oil swaps | April 2022 - June 2022 | 1,092,000 | 12,000 | $65.28 | |||||||||||||||||||
| July 2022 - September 2022 | 782,000 | 8,500 | 65.46 | ||||||||||||||||||||
| October 2022 - December 2022 | 690,000 | 7,500 | 65.63 | ||||||||||||||||||||
| January 2023 - March 2023 | 225,000 | 2,500 | 73.51 | ||||||||||||||||||||
| April 2023 - June 2023 | 227,500 | 2,500 | 73.25 | ||||||||||||||||||||
| July 2023 - September 2023 | 92,000 | 1,000 | 72.98 | ||||||||||||||||||||
| October 2023 - December 2023 | 92,000 | 1,000 | 72.98 | ||||||||||||||||||||
| Period | Volume (Bbls) | Volume (Bbls/d) | Wtd. Avg. Collar Price Ranges ($/Bbl)(2) | ||||||||||||||||||||
| Crude oil collars | |||||||||||||||||||||||
| NYMEX WTI | April 2022 - June 2022 | 227,500 | 2,500 | $63.20 - $72.41 | |||||||||||||||||||
| July 2022 - September 2022 | 276,000 | 3,000 | 75.00 - 92.46 | ||||||||||||||||||||
| October 2022 - December 2022 | 276,000 | 3,000 | 75.00 - 92.46 | ||||||||||||||||||||
| January 2023 - March 2023 | 450,000 | 5,000 | 73.00 - 85.68 | ||||||||||||||||||||
| April 2023 - June 2023 | 455,000 | 5,000 | 73.00 - 85.68 | ||||||||||||||||||||
| July 2023 - September 2023 | 276,000 | 3,000 | 73.33 - 85.66 | ||||||||||||||||||||
| October 2023 - December 2023 | 276,000 | 3,000 | 73.33 - 85.66 | ||||||||||||||||||||
| ICE Brent | April 2022 - June 2022 | 91,000 | 1,000 | $90.00 - $105.20 | |||||||||||||||||||
| Period | Volume (Bbls) | Volume (Bbls/d) | Wtd. Avg. Differential ($/Bbl)(3) | ||||||||||||||||||||
| Crude oil basis differential swaps | April 2022 - June 2022 | 637,000 | 7,000 | $0.34 | |||||||||||||||||||
| July 2022 - September 2022 | 552,000 | 6,000 | 0.29 | ||||||||||||||||||||
| October 2022 - December 2022 | 552,000 | 6,000 | 0.29 | ||||||||||||||||||||
| Period | Volume (Bbls) | Volume (Bbls/d) | Wtd. Avg. Differential ($/Bbl)(4) | ||||||||||||||||||||
Crude oil roll differential swaps | April 2022 - June 2022 | 910,000 | 10,000 | $0.71 | |||||||||||||||||||
| July 2022 - September 2022 | 920,000 | 10,000 | 0.71 | ||||||||||||||||||||
| October 2022 - December 2022 | 920,000 | 10,000 | 0.71 | ||||||||||||||||||||
(1) These crude oil swap transactions are settled based on the NYMEX WTI index price on each trading day within the specified monthly settlement period versus the contractual swap price for the volumes stipulated.
(2) These crude oil collars are settled based on the NYMEX WTI or ICE Brent index price, as applicable, on each trading day within the specified monthly settlement period versus the contractual floor and ceiling prices for the volumes stipulated.
(3) These crude oil basis swap transactions are settled based on the difference between the arithmetic average of ARGUS MIDLAND WTI and ARGUS WTI CUSHING indices, during each applicable monthly settlement period.
(4) These crude oil roll swap transactions are settled based on the difference between the arithmetic average of NYMEX WTI calendar month prices and the physical crude oil delivery month price.
| Period | Volume (MMBtu) | Volume (MMBtu/d) | Wtd. Avg. Gas Price ($/MMBtu)(1) | ||||||||||||||||||||
| Natural gas swaps | April 2022 - June 2022 | 2,730,000 | 30,000 | $3.24 | |||||||||||||||||||
| July 2022 - September 2022 | 2,760,000 | 30,000 | 3.24 | ||||||||||||||||||||
| October 2022 - December 2022 | 1,540,000 | 16,739 | 3.15 | ||||||||||||||||||||
| Period | Volume (MMBtu) | Volume (MMBtu/d) | Wtd. Avg. Differential ($/MMBtu)(2) | ||||||||||||||||||||
| Natural gas basis differential swaps | April 2022 - June 2022 | 1,820,000 | 20,000 | $(0.45) | |||||||||||||||||||
| July 2022 - September 2022 | 1,840,000 | 20,000 | (0.45) | ||||||||||||||||||||
| October 2022 - December 2022 | 1,840,000 | 20,000 | (0.45) | ||||||||||||||||||||
| January 2023 - March 2023 | 2,250,000 | 25,000 | (1.11) | ||||||||||||||||||||
| April 2023 - June 2023 | 2,275,000 | 25,000 | (1.11) | ||||||||||||||||||||
| July 2023 - September 2023 | 2,300,000 | 25,000 | (1.11) | ||||||||||||||||||||
| October 2023 - December 2023 | 2,300,000 | 25,000 | (1.11) | ||||||||||||||||||||
| Period | Volume (MMBtu) | Volume (MMBtu/d) | Wtd. Avg. Collar Price Ranges ($/MMBtu)(3) | ||||||||||||||||||||
Natural gas collars | April 2022 - June 2022 | 1,820,000 | 20,000 | $3.50 - $3.97 | |||||||||||||||||||
| July 2022 - September 2022 | 1,840,000 | 20,000 | 3.50 - 3.97 | ||||||||||||||||||||
| October 2022 - December 2022 | 2,450,000 | 26,630 | 3.87 - 5.06 | ||||||||||||||||||||
| January 2023 - March 2023 | 4,500,000 | 50,000 | 4.00 - 7.12 | ||||||||||||||||||||
| April 2023 - June 2023 | 3,640,000 | 40,000 | 3.56 - 6.86 | ||||||||||||||||||||
| July 2023 - September 2023 | 3,680,000 | 40,000 | 3.56 - 6.86 | ||||||||||||||||||||
| October 2023 - December 2023 | 3,680,000 | 40,000 | 3.60 - 7.28 | ||||||||||||||||||||
| January 2024 - March 2024 | 1,820,000 | 20,000 | 3.25 - 5.31 | ||||||||||||||||||||
(1) 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.