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Supplemental Disclosures About Natural Gas, Oil and NGL Producing Activities (unaudited) | 12 Months Ended
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Dec. 31, 2022
Extractive Industries [Abstract] |
Exploration Expense |
Supplemental Disclosures About Natural Gas, Oil and NGL Producing Activities (unaudited) |
Certain reserves and production information was previously disclosed in a per barrel of oil equivalent. As the majority of our production profile consists of natural gas, we have converted this information, including prior periods, from a per barrel of oil equivalent, to a per one thousand cubic feet of natural gas equivalent, referred to, on such a converted basis, as per Mcfe. Net Capitalized Costs Capitalized costs related to our natural gas, oil and NGL producing activities are summarized as follows:
|  | Successor
|  | December 31, 2022 |  | December 31, 2021
Natural gas and oil properties: |  |  |  |
Proved |  | $ | 11,096 |  |  | $ | 7,682 |
Unproved |  | 2,022 |  |  | 1,530 |
Total |  | 13,118 |  |  | 9,212 |
Less accumulated depreciation, depletion and amortization |  | (2,373) |  |  | (882) |
Net capitalized costs |  | $ | 10,745 |  |  | $ | 8,330 |
Unproved properties as of December 31, 2022 and 2021, consisted mainly of leasehold acquired through our Vine Acquisition and Marcellus Acquisition. We will continue to evaluate our unproved properties, and although the timing of the ultimate evaluation or disposition of the properties cannot be determined, we can expect the majority of our unproved properties not held by production to be transferred into the amortization base over the next five years. Costs Incurred in Natural Gas and Oil Property Acquisition, Exploration and Development Costs incurred in natural gas and oil property acquisition, exploration and development, including capitalized interest and asset retirement costs, are summarized as follows:
|  | Successor |  |  | Predecessor
|  | Year Ended December 31, 2022 |  | Period from February 10, 2021 through December 31, 2021 |  |  | Period from January 1, 2021 through February 9, 2021 |  | Year Ended December 31, 2020
Acquisition of properties(a): |  |  |  |  |  |  |  |  |
Proved properties |  | $ | 2,321 |  |  | $ | 2,183 |  |  |  | $ | — |  |  | $ | 3 |
Unproved properties |  | 795 |  |  | 1,121 |  |  |  | — |  |  | 6 |
Exploratory costs |  | 15 |  |  | 31 |  |  |  | — |  |  | 8 |
Development costs |  | 1,918 |  |  | 717 |  |  |  | 58 |  |  | 887 |
Costs incurred |  | $ | 5,049 |  |  | $ | 4,052 |  |  |  | $ | 58 |  |  | $ | 904 |
___________________________________________ (a) Includes $2.31 billion and $0.79 billion of proved and unproved property acquisitions, respectively, related to our Marcellus Acquisition in 2022. Includes $2.18 billion and $1.10 billion of proved and unproved property acquisitions, respectively, related to our Vine Acquisition in 2021. Results of Operations from Natural Gas, Oil and NGL Producing Activities The following table includes revenues and expenses associated directly with our natural gas, oil and NGL producing activities for the periods presented. It does not include any derivative activity, interest costs or indirect general and administrative costs and, therefore, is not necessarily indicative of the contribution to consolidated net operating results of our natural gas, oil and NGL operations.
|  | Successor |  |  | Predecessor
|  | Year Ended December 31, 2022 |  | Period from February 10, 2021 through December 31, 2021 |  |  | Period from January 1, 2021 through February 9, 2021 |  | Year Ended December 31, 2020
Natural gas, oil and NGL sales |  | $ | 9,892 |  |  | $ | 4,401 |  |  |  | $ | 398 |  |  | $ | 2,745 |
Production expenses |  | (475) |  |  | (297) |  |  |  | (32) |  |  | (373) |
Gathering, processing and transportation expenses |  | (1,059) |  |  | (780) |  |  |  | (102) |  |  | (1,082) |
Severance and ad valorem taxes |  | (242) |  |  | (158) |  |  |  | (18) |  |  | (149) |
Exploration |  | (23) |  |  | (7) |  |  |  | (2) |  |  | (427) |
Depletion and depreciation |  | (1,703) |  |  | (882) |  |  |  | (64) |  |  | (1,014) |
Accretion of asset retirement obligations |  | (17) |  |  | (11) |  |  |  | (1) |  |  | (12) |
Impairment of natural gas and oil properties |  | — |  |  | — |  |  |  | — |  |  | (8,446) |
Imputed income tax provision(a) |  | (1,440) |  |  | (535) |  |  |  | (42) |  |  | 1,988 |
Results of operations from natural gas, oil and NGL producing activities |  | $ | 4,933 |  |  | $ | 1,731 |  |  |  | $ | 137 |  |  | $ | (6,770) |
___________________________________________ (a) The imputed income tax provision is hypothetical (at the statutory tax rate) and determined without regard to our deduction for general and administrative expenses, interest costs and other income tax credits and deductions, nor whether the hypothetical tax provision (benefit) will be payable (receivable). Natural Gas, Oil and NGL Reserve Quantities Our petroleum engineers and independent petroleum engineering firms estimated all of our proved reserves as of December 31, 2022, 2021 and 2020. Independent petroleum engineering firm Netherland, Sewell & Associates, Inc. estimated an aggregate of 92% of our estimated proved reserves (by volume) as of December 31, 2022. Proved natural gas, oil and NGL reserves are those quantities of natural gas, oil and NGL which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible – from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations – prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. Based on reserve reporting rules, the price is calculated using the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within the period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions. A project to extract hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time. The area of the reservoir considered as proved includes: (i) the area identified by drilling and limited by fluid contacts, if any, and (ii) adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible natural gas or oil on the basis of available geoscience and engineering data. In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons as seen in a well penetration unless geoscience, engineering or performance data and reliable technology establish a lower contact with reasonable certainty. Where direct observation from well penetrations has defined a highest known oil elevation and the potential exists for an associated natural gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering or performance data and reliable technology establish the higher contact with reasonable certainty. Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when: (i) successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and (ii) the project has been approved for development by all necessary parties and entities, including governmental entities. The information provided below on our natural gas, oil and NGL reserves is presented in accordance with regulations prescribed by the SEC. Our reserve estimates are generally based upon extrapolation of historical production trends, analogy to similar properties and volumetric calculations. Accordingly, these estimates will change as future information becomes available and as commodity prices change. These changes could be material and could occur in the near term. Presented below is a summary of changes in estimated proved reserves for the periods presented:
|  | Natural Gas |  | Oil |  | NGL |  | Total
|  | (bcf) |  | (mmbbl) |  | (mmbbl) |  | (bcfe)
December 31, 2022 |  |  |  |  |  |  |  |
Proved reserves, beginning of period (Successor) |  | 7,824 |  |  | 209.7 |  |  | 82.0 |  |  | 9,573 |
Extensions, discoveries and other additions |  | 60 |  |  | 2.1 |  |  | 1.5 |  |  | 82 |
Revisions of previous estimates |  | 1,989 |  |  | 22.5 |  |  | 5.0 |  |  | 2,155 |
Production |  | (1,308) |  |  | (19.4) |  |  | (6.0) |  |  | (1,461) |
Sale of reserves-in-place |  | (122) |  |  | (16.5) |  |  | (8.6) |  |  | (273) |
Purchase of reserves-in-place |  | 2,926 |  |  | — |  |  | — |  |  | 2,926 |
Proved reserves, end of period (Successor) |  | 11,369 |  |  | 198.4 |  |  | 73.9 |  |  | 13,002 |
Proved developed reserves: |  |  |  |  |  |  |  |
Beginning of period (Successor) |  | 4,246 |  |  | 165.7 |  |  | 61.7 |  |  | 5,610 |
End of period (Successor) |  | 7,385 |  |  | 157.2 |  |  | 58.9 |  |  | 8,681 |
Proved undeveloped reserves: |  |  |  |  |  |  |  |
Beginning of period (Successor) |  | 3,578 |  |  | 44.0 |  |  | 20.3 |  |  | 3,963 |
End of period(a) (Successor) |  | 3,984 |  |  | 41.2 |  |  | 15.0 |  |  | 4,321 |
|  | Natural Gas |  | Oil |  | NGL |  | Total
|  | (bcf) |  | (mmbbl) |  | (mmbbl) |  | (bcfe)
December 31, 2021 |  |  |  |  |  |  |  |
Proved reserves, beginning of period (Predecessor) |  | 3,530 |  |  | 161.3 |  |  | 52.0 |  |  | 4,809 |
Extensions, discoveries and other additions |  | 1,744 |  |  | 41.0 |  |  | 16.9 |  |  | 2,091 |
Revisions of previous estimates |  | 1,522 |  |  | 33.3 |  |  | 21.1 |  |  | 1,848 |
Production |  | (807) |  |  | (25.9) |  |  | (8.0) |  |  | (1,010) |
Sale of reserves-in-place |  | — |  |  | — |  |  | — |  |  | — |
Purchase of reserves-in-place |  | 1,835 |  |  | — |  |  | — |  |  | 1,835 |
Proved reserves, end of period (Successor) |  | 7,824 |  |  | 209.7 |  |  | 82.0 |  |  | 9,573 |
Proved developed reserves: |  |  |  |  |  |  |  |
Beginning of period (Predecessor) |  | 3,196 |  |  | 158.1 |  |  | 51.4 |  |  | 4,452 |
End of period (Successor) |  | 4,246 |  |  | 165.7 |  |  | 61.7 |  |  | 5,610 |
Proved undeveloped reserves: |  |  |  |  |  |  |  |
Beginning of period (Predecessor) |  | 334 |  |  | 3.2 |  |  | 0.6 |  |  | 357 |
End of period(a) (Successor) |  | 3,578 |  |  | 44.0 |  |  | 20.3 |  |  | 3,963 |
December 31, 2020 |  |  |  |  |  |  |  |
Proved reserves, beginning of period (Predecessor) |  | 6,566 |  |  | 358.0 |  |  | 120.0 |  |  | 9,434 |
Extensions, discoveries and other additions |  | 100 |  |  | 1.1 |  |  | 0.4 |  |  | 109 |
Revisions of previous estimates |  | (2,326) |  |  | (148.2) |  |  | (50.6) |  |  | (3,519) |
Production |  | (684) |  |  | (37.3) |  |  | (11.3) |  |  | (976) |
Sale of reserves-in-place |  | (126) |  |  | (12.3) |  |  | (6.5) |  |  | (239) |
Purchase of reserves-in-place |  | — |  |  | — |  |  | — |  |  | — |
Proved reserves, end of period (Predecessor) |  | 3,530 |  |  | 161.3 |  |  | 52.0 |  |  | 4,809 |
Proved developed reserves: |  |  |  |  |  |  |  |
Beginning of period (Predecessor) |  | 3,377 |  |  | 201.4 |  |  | 82.1 |  |  | 5,078 |
End of period (Predecessor) |  | 3,196 |  |  | 158.1 |  |  | 51.4 |  |  | 4,452 |
Proved undeveloped reserves: |  |  |  |  |  |  |  |
Beginning of period (Predecessor) |  | 3,189 |  |  | 156.6 |  |  | 37.9 |  |  | 4,356 |
End of period(a) (Predecessor) |  | 334 |  |  | 3.2 |  |  | 0.6 |  |  | 357 |
___________________________________________ (a) As of December 31, 2022, 2021 and 2020, there were no PUDs that had remained undeveloped for five years or more. During 2022, we acquired 2,926 bcfe primarily related to the Marcellus Acquisition. We recorded extensions and discoveries of 82 bcfe primarily related to new PUDs and previously unproved producing wells in emerging plays. We recorded 2,155 bcfe of upward revisions of previous estimates, which consisted of 866 bcfe of revisions to PUDs primarily due to development plan optimization through prioritizing longer laterals and multi-well pad development in the Haynesville, 1,156 bcfe of revisions to existing or new proved developed properties primarily due to performance and 133 bcfe of revisions due to higher natural gas, oil and NGL prices in 2022. The natural gas, oil and NGL prices used in computing our reserves as of December 31, 2022, were $6.36 per mcf, $93.67 per bbl and $43.58 per bbl, respectively, before basis differential adjustments. During 2021, we acquired 1,835 bcfe primarily related to the Vine Acquisition. We recorded extensions and discoveries of 2,091 bcfe following our emergence from bankruptcy on February 9, 2021, and certainty regarding our ability to finance the development of our proved reserves over a five-year period. We recorded 1,848 bcfe of upward revisions of previous estimates, which consisted of 1,284 bcfe due to lateral length adjustments, performance and updates to our five-year development plan and 564 bcfe due to higher natural gas, oil and NGL prices in 2021. The natural gas, oil and NGL prices used in computing our reserves as of December 31, 2021, were $3.60 per mcf, $66.56 per bbl and $35.81 per bbl, respectively, before basis differential adjustments. During 2020, we recorded extensions and discoveries of 109 bcfe primarily in the Marcellus and Haynesville primarily related to successfully drilled new well additions. We sold 239 bcfe of proved reserves for approximately $136 million primarily in the Mid-Continent. We recorded 3,519 bcfe of downward revisions of previous estimates consisting of 2,538 bcfe of downward revisions due to updates to our five-year development plan in contemplation of ongoing market conditions and uncertainty regarding our ability to finance the development of our proved reserves over a five-year period, downward revisions of 1,248 bcfe due to lower natural gas, oil and NGL prices in 2020, and upward revisions of 267 bcfe due to ongoing portfolio evaluation including performance adjustments. The natural gas, oil and NGL prices used in computing our reserves as of December 31, 2020, were $1.98 per mcf, $39.57 per bbl and $17.32 per bbl, respectively, before basis differential adjustments. Standardized Measure of Discounted Future Net Cash Flows Accounting Standards Codification Topic 932 prescribes guidelines for computing a standardized measure of future net cash flows and changes therein relating to estimated proved reserves. Chesapeake has followed these guidelines which are briefly discussed below. Future cash inflows and future production and development costs as of December 31, 2022, 2021 and 2020 were determined by applying the average of the first-day-of-the-month prices for the 12 months of the year and year-end costs to the estimated quantities of natural gas, oil and NGL to be produced. Actual future prices and costs may be materially higher or lower than the prices and costs used. For each year, estimates are made of quantities of proved reserves and the future periods during which they are expected to be produced based on continuation of the economic conditions applied for that year. Estimated future income taxes are computed using current statutory income tax rates including consideration of the current tax basis of the properties and related carryforwards, giving effect to permanent differences and tax credits. The resulting future net cash flows are reduced to present value amounts by applying a 10% annual discount factor. The assumptions used to compute the standardized measure are those prescribed by the Financial Accounting Standards Board and do not necessarily reflect our expectations of actual revenue to be derived from those reserves nor their present worth. The limitations inherent in the reserve quantity estimation process, as discussed previously, are equally applicable to the standardized measure computations since these estimates reflect the valuation process. The following summary sets forth our future net cash flows relating to proved natural gas, oil and NGL reserves based on the standardized measure:
|  | Years Ended December 31, |
|  | 2022 |  | 2021 |  | 2020 |
Future cash inflows |  | $ | 76,626 |  | (a) | $ | 33,700 |  | (b) | $ | 8,247 |  | (c)
Future production costs |  | (10,177) |  |  | (6,735) |  |  | (2,963) |  |
Future development costs |  | (5,343) |  | (d) | (3,687) |  | (e) | (563) |  | (f)
Future income tax provisions |  | (10,440) |  |  | (2,254) |  |  | (9) |  |
Future net cash flows |  | 50,666 |  |  | 21,024 |  |  | 4,712 |  |
Less effect of a 10% discount factor |  | (24,361) |  |  | (8,737) |  |  | (1,626) |  |
Standardized measure of discounted future net cash flows |  | $ | 26,305 |  |  | $ | 12,287 |  |  | $ | 3,086 |  |
___________________________________________ (a) Calculated using prices of $6.36 per mcf of natural gas, $93.67 per bbl of oil and $43.58 per bbl of NGL, before basis differential adjustments. (b) Calculated using prices of $3.60 per mcf of natural gas, $66.56 per bbl of oil and $35.81 per bbl of NGL, before basis differential adjustments. (c) Calculated using prices of $1.98 per mcf of natural gas, $39.57 per bbl of oil and $17.32 per bbl of NGL, before basis differential adjustments. (d) Included approximately $979 million of future plugging and abandonment costs as of December 31, 2022. (e) Included approximately $846 million of future plugging and abandonment costs as of December 31, 2021. (f) Included approximately $429 million of future plugging and abandonment costs as of December 31, 2020. The principal sources of change in the standardized measure of discounted future net cash flows are as follows:
|  | Years Ended December 31,
|  | 2022 |  | 2021 |  | 2020
Standardized measure, beginning of period(a) |  | $ | 12,287 |  |  | $ | 3,086 |  |  | $ | 9,000 |
Sales of natural gas and oil produced, net of production costs and gathering processing and transportation(b) |  | (8,116) |  |  | (3,414) |  |  | (1,140) |
Net changes in prices and production costs |  | 14,256 |  |  | 6,674 |  |  | (5,576) |
Extensions and discoveries, net of production and development costs |  | 251 |  |  | 2,834 |  |  | 71 |
Changes in estimated future development costs |  | (1,512) |  |  | (459) |  |  | 1,933 |
Previously estimated development costs incurred during the period |  | 690 |  |  | 130 |  |  | 665 |
Revisions of previous quantity estimates |  | 6,697 |  |  | 2,034 |  |  | (1,839) |
Purchase of reserves-in-place |  | 7,047 |  |  | 2,807 |  |  | — |
Sales of reserves-in-place |  | (402) |  |  | — |  |  | (112) |
Accretion of discount |  | 1,371 |  |  | 309 |  |  | 902 |
Net change in income taxes |  | (4,972) |  |  | (1,423) |  |  | 14 |
Changes in production rates and other |  | (1,292) |  |  | (291) |  |  | (832) |
Standardized measure, end of period(a) |  | $ | 26,305 |  |  | $ | 12,287 |  |  | $ | 3,086 |
___________________________________________ (a) The impact of cash flow hedges has not been included in any of the periods presented. (b) Excludes gains and losses on derivatives. Production costs includes severance and ad valorem taxes.

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