Annual report pursuant to Section 13 and 15(d)

SUPPLEMENTAL DISCLOSURES ABOUT NATURAL GAS PRODUCING ACTIVITIES

v3.24.0.1
SUPPLEMENTAL DISCLOSURES ABOUT NATURAL GAS PRODUCING ACTIVITIES
 12 Months Ended
Dec. 31, 2023
Extractive Industries [Abstract]  
SUPPLEMENTAL DISCLOSURES ABOUT NATURAL GAS PRODUCING ACTIVITIES
SUPPLEMENTAL DISCLOSURES ABOUT NATURAL GAS PRODUCING ACTIVITIES    
In accordance with FASB and SEC disclosure requirements for natural gas producing activities, this section provides supplemental information on Tellurian’s natural gas producing activities in six separate tables. Tables I through III provide historical cost information pertaining to costs incurred in exploration, property acquisitions and development; capitalized costs; and results of operations. Tables IV through VI present information on the Company’s estimated net proved reserve quantities, standardized measure of estimated discounted future net cash flows related to proved reserves and changes in estimated discounted future net cash flows.
Table I — Capitalized Costs Related to Natural Gas Producing Activities
Capitalized costs related to Tellurian’s natural gas producing activities are summarized as follows (in thousands):
December 31,
2023 2022 2021
Proved properties $ 561,303  $ 468,351  $ 113,950 
Unproved properties —  —  — 
Gross capitalized costs 561,303  468,351  113,950 
Accumulated DD&A (187,171) (92,423) (48,637)
Net capitalized costs $ 374,132  $ 375,928  $ 65,313 
Table II — Costs Incurred in Property Acquisitions,Exploration and Development
Costs incurred in natural gas property acquisition (inclusive of producing well costs), exploration and development activities are summarized as follows (in thousands):
Year Ended December 31,
2023 2022 2021
Property acquisitions:
Proved $ —  $ 135,974  $ 3,409 
Unproved —  —  — 
Exploration costs —  —  — 
Development costs 116,045  210,546  28,955 
Costs incurred $ 116,045  $ 346,520  $ 32,364 
Table III — Results of Operations for Natural Gas Producing Activities
The following table includes revenues and expenses directly associated with our natural gas and condensate producing activities. It does not include any 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 operations. Tellurian’s results of operations from natural gas and condensate producing activities for the periods presented are as follows (in thousands):
Year Ended December 31,
2023 2022 2021
Natural gas sales $ 166,128  $ 270,977  $ 51,499 
Operating costs 88,276  53,963  20,576 
Depreciation, depletion and amortization 95,202  43,966  10,998 
Total operating costs and expenses 183,478  97,929  31,574 
Results of operations $ (17,350) $ 173,048  $ 19,925 
Table IV — Natural Gas Reserve Quantity Information
Our estimated proved reserves are located in Louisiana. We caution that there are many uncertainties inherent in estimating proved reserve quantities and in projecting future production rates and the timing of development expenditures. Accordingly, these estimates are expected to change as further information becomes available. Material revisions of reserve estimates may occur in the future, development and production of the natural gas and condensate reserves may not occur in the periods assumed, and actual prices realized and actual costs incurred may vary significantly from those used in these estimates.
The estimates of our proved reserves as of December 31, 2023, 2022 and 2021 have been prepared by Netherland, Sewell & Associates, Inc., independent petroleum consultants.
Gas
(MMcf)		 Gas Equivalent
(MMcfe)
Proved reserves:
December 31, 2020 99,508  99,508 
Extensions, discoveries and other additions 202,897  202,897 
Revisions of previous estimates 35,237  35,237 
Production (14,306) (14,306)
Sale of reserves-in-place —  — 
Purchases of reserves-in-place —  — 
December 31, 2021 323,336  323,336 
Extensions, discoveries and other additions 113,047  113,047 
Revisions of previous estimates (52,185) (52,185)
Production (47,322) (47,322)
Sale of reserves-in-place —  — 
Purchases of reserves-in-place 108,017  108,017 
December 31, 2022 444,893  444,893 
Extensions, discoveries and other additions 983  983 
Revisions of previous estimates (179,737) (179,737)
Production (72,476) (72,476)
Sale of reserves-in-place (15,627) (15,627)
Purchases of reserves-in-place —  — 
December 31, 2023 178,036  178,036 
Proved developed reserves:
December 31, 2021 73,927  73,927 
December 31, 2022 218,382  218,382 
December 31, 2023 178,036  178,036 
Proved undeveloped reserves:
December 31, 2021 249,409  249,409 
December 31, 2022 226,511  226,511 
December 31, 2023 —  — 
2022 to 2023 Overall Reserve Changes
•The Company added 1 Bcfe of proved developed reserves from drilling activities.
•The Company had total negative revisions of approximately 180 Bcfe, comprised primarily of a 170 Bcfe negative revision from removing proved undeveloped locations due to uncertainty regarding the Company's future commitment to capital, a 12 Bcfe negative revision from decreases in commodity prices, a 26 Bcfe negative revision from well performance and a 27 Bcfe positive revision from changes in ownership.

•The Company divested 16 Bcfe of proved undeveloped reserves.
2022 to 2023 PUD Changes
•The Company had total negative revisions of approximately 170 Bcfe from removing proved undeveloped locations due to uncertainty regarding the Company's future commitment to capital
•The Company divested 16 Bcfe of proved undeveloped reserves.
•The Company converted approximately 41 Bcfe from proved undeveloped to proved developed reserves.
2021 to 2022 Overall Reserve Changes
•The Company added 113 Bcfe of proved reserves comprised of 89 Bcfe from additional proved undeveloped locations and 24 Bcfe of proved developed reserves from drilling activities.
•The Company had total negative revisions of approximately 52 Bcfe, comprised primarily of a 38 Bcfe negative revision from removing proved undeveloped locations that now fall outside of the SEC mandated five-year development window, a 25 Bcfe negative revision from changes in lateral lengths and ownership, a 3 Bcfe negative revision from increased operational costs, partially offset by an 8 Bcfe positive revision from improved well performance, and a 6 Bcfe positive revision due to an increase in commodity prices. The removal of the proved undeveloped locations that fell outside of the five-year development window resulted from a re-prioritization of activity due to (i) our asset acquisition and (ii) unanticipated third party development activity that caused an existing well to be shut in and unable to return to production and thereby required us to alter our drilling schedule to preserve the affected leases.
•During the year ending December 31, 2022, we acquired approximately 108 Bcfe primarily related to the acquisition of natural gas assets.
2021 to 2022 PUD Changes
•The Company added approximately 89 Bcfe from additional proved undeveloped locations.
•The Company had total negative revisions of approximately 44 Bcfe, comprised of a 38 Bcfe negative revision from removing proved undeveloped locations that now fall outside of the SEC mandated five-year development window, a 13 Bcfe negative revision from changes in lateral lengths and ownership, partially offset by a 5 Bcfe positive revision from improved well performance, and a 2 Bcfe positive revision due to an increase in commodity prices.
•During the year ending December 31, 2022, we acquired approximately 71 Bcfe of proved undeveloped reserves primarily related to the acquisition of natural gas assets.
•The Company converted approximately 138 Bcfe from proved undeveloped reserves to proved developed reserves.
2020 to 2021 Overall Reserve Changes
•Added 203 Bcfe of proved reserves comprised of 152 Bcfe from additional proved undeveloped locations and 51 Bcfe of proved developed reserves from drilling activities.
•Had total positive revisions of approximately 35 Bcfe, comprised primarily of a 9 Bcfe positive revision due to an increase in commodity prices, a 15 Bcfe positive revision from changes in ownership and an 11 Bcfe positive revision from improved well performance.
2020 to 2021 PUD Changes
•Added approximately 152 Bcfe from additional proved undeveloped locations.
•Had total positive revisions of approximately 25 Bcfe, comprised of a 3 Bcfe positive revision due to an increase in commodity prices, a 16 Bcfe positive revision from changes in ownership and a 6 Bcfe positive revision from improved well performance.
Table V — Standardized Measure of Discounted Future Net Cash Flows Related to Proved Natural Gas Reserves
ASC 932 prescribes guidelines for computing a standardized measure of future net cash flows and changes therein relating to estimated proved reserves. Tellurian has followed these guidelines, which are briefly discussed below.
Future cash inflows and future production and development costs as of December 31, 2023, 2022 and 2021 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 and condensate 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 the 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 FASB and do not necessarily reflect our expectations of actual revenue to be derived from those reserves or 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 and condensate reserves based on the standardized measure (in thousands):
Year Ended December 31,
2023 2022 2021
Future cash inflows $ 326,246  $ 2,441,930  $ 945,651 
Future production costs (102,356) (341,925) (133,909)
Future development costs (56,207) (360,107) (211,836)
Future income tax provisions —  (257,908) (54,401)
Future net cash flows 167,683  1,481,990  545,505 
Less effect of a 10% discount factor (42,254) (445,686) (181,302)
Standardized measure of discounted future net cash flows $ 125,429  $ 1,036,304  $ 364,203 
Table VI — Changes in Standardized Measure of Discounted Future Net Cash Flows Related to Proved Natural Gas Reserves
The following sets forth the changes in the standardized measure of discounted future net cash flows (in thousands):
December 31, 2020 $ 6,885 
Sales and transfers of gas and condensate produced, net of production costs (39,806)
Net changes in prices and production costs 110,850 
Extensions, discoveries, additions and improved recovery, net of related costs 255,246 
Development costs incurred — 
Revisions of estimated development costs 10,643 
Revisions of previous quantity estimates 35,012 
Accretion of discount 688 
Net change in income taxes (27,455)
Purchases of reserves in place — 
Sales of reserves in place — 
Changes in timing and other 12,140 
December 31, 2021 $ 364,203 
Sales and transfers of gas and condensate produced, net of production costs (236,374)
Net changes in prices and production costs 503,099 
Extensions, discoveries, additions and improved recovery, net of related costs 255,970 
Development costs incurred 154,931 
Revisions of estimated development costs (105,352)
Revisions of previous quantity estimates (143,398)
Accretion of discount 36,420 
Net change in income taxes (127,154)
Purchases of reserves in place 262,050 
Sales of reserves in place — 
Changes in timing and other 71,909 
December 31, 2022 $ 1,036,304 
Sales and transfers of gas and condensate produced, net of production costs (101,438)
Net changes in prices and production costs (660,129)
Extensions, discoveries, additions and improved recovery, net of related costs 1,227 
Development costs incurred 75,788 
Revisions of estimated development costs (88,121)
Revisions of previous quantity estimates (331,376)
Accretion of discount 63,350 
Net change in income taxes 154,609 
Purchases of reserves in place — 
Sales of reserves in place (30,124)
Changes in timing and other 5,339 
December 31, 2023 $ 125,429