Annual report pursuant to Section 13 and 15(d)

SUPPLEMENTAL DISCLOSURES ABOUT NATURAL GAS PRODUCING ACTIVITIES

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SUPPLEMENTAL DISCLOSURES ABOUT NATURAL GAS PRODUCING ACTIVITIES
 12 Months Ended
Dec. 31, 2021
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,
2021 2020 2019
Proved properties $ 113,950  $ 62,718  $ 142,494 
Unproved properties —  —  — 
Gross capitalized costs 113,950  62,718  142,494 
Accumulated DD&A (48,637) (37,639) (21,010)
Net capitalized costs $ 65,313  $ 25,079  $ 121,484 

Table II — Costs Incurred in Exploration, Property Acquisitions 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,
2021 2020 2019
Property acquisitions:
Proved $ 3,409  $ 1,307  $ 45,484 
Unproved —  —  — 
Exploration costs —  —  — 
Development 28,955  —  800 
Costs incurred $ 32,364  $ 1,307  $ 46,284 

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,
2021 2020 2019
Natural gas sales $ 51,499  $ 30,441  $ 28,774 
Operating costs 20,576  15,814  14,923 
Depreciation, depletion and amortization 10,998  16,703  19,736 
Impairment charge —  81,065  — 
Total operating costs and expenses 31,574  113,582  34,659 
Results of operations $ 19,925  $ (83,141) $ (5,885)
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, 2021, 2020 and 2019 have been prepared by Netherland, Sewell & Associates, Inc., independent petroleum consultants.
Gas
(MMcf)		 Condensate
(Mbbl)		 Gas Equivalent
(MMcfe)
Proved reserves:
December 31, 2018 264,854  7  264,899 
Extensions, discoveries and other additions 12,848  —  12,848 
Revisions of previous estimates 4,737  (6) 4,696 
Production (13,901) (1) (13,905)
Sale of reserves-in-place —  —  — 
Purchases of reserves-in-place —  —  — 
December 31, 2019 268,538  —  268,538 
Extensions, discoveries and other additions —  —  — 
Revisions of previous estimates (152,132) —  (152,132)
Production (16,898) —  (16,898)
Sale of reserves-in-place —  —  — 
Purchases of reserves-in-place —  —  — 
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 
Proved developed reserves:
December 31, 2019 30,699  —  30,699 
December 31, 2020 26,593  —  26,593 
December 31, 2021 73,927  —  73,927 
Proved undeveloped reserves:
December 31, 2019 237,839  —  237,839 
December 31, 2020 72,915  —  72,915 
December 31, 2021 249,409  —  249,409 
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.
2019 to 2020 Overall Reserve Changes
•Had total negative revisions of approximately 152 Bcfe, comprised primarily of a 149 Bcfe negative revision due to the downturn in commodity prices and a 17 Bcfe negative revision from the loss of leases. These downward revisions were offset by a 14 Bcfe positive revision due to improved well performance.
2019 to 2020 PUD Changes
•Had total negative revisions of approximately 165 Bcfe, comprised of a 148 Bcfe negative revision due to the downturn in commodity prices and a 17 Bcfe negative revision from lease expirations.
2018 to 2019 Overall Reserve Changes
•Added approximately 13 Bcfe of proved reserves, comprised of 12 Bcfe from additional proved undeveloped locations and 1 Bcfe from drilling activities.
•Had total positive revisions of approximately 4 Bcfe, comprised of a 4 Bcfe negative revision due to prices, a 2 Bcfe negative revision from changes in operating expenses, a 9 Bcfe positive revision from well performance and a 1 Bcfe positive revision from changes in ownership.
2018 to 2019 PUD Changes
•Converted approximately 29 Bcfe to proved developed reserves.
•Added approximately 12 Bcfe from additional proved undeveloped locations.
•Had total positive revisions of approximately 8 Bcfe, comprised primarily of a 9 Bcfe positive revision from well performance, a 2 Bcfe negative revision due to prices and a 1 Bcfe positive revision from changes in ownership.
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, 2021, 2020 and 2019 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,
2021 2020 2019
Future cash inflows $ 945,651  $ 132,563  $ 534,577 
Future production costs (133,909) (34,624) (102,268)
Future development costs (211,836) (71,557) (287,111)
Future income tax provisions (54,401) —  (6,612)
Future net cash flows 545,505  26,382  138,586 
Less effect of a 10% discount factor (181,302) (19,497) (85,415)
Standardized measure of discounted future net cash flows $ 364,203  $ 6,885  $ 53,171 
Table VI — Changes in Standardized Measure of Discounted Future Net Cash Flows Related to Proved Natural Gas Reserves
The following table sets forth the changes in the standardized measure of discounted future net cash flows (in thousands):
December 31, 2018 $ 145,811 
Sales and transfers of gas and condensate produced, net of production costs (21,704)
Net changes in prices and production costs (134,366)
Extensions, discoveries, additions and improved recovery, net of related costs 2,019 
Development costs incurred 23,485 
Revisions of estimated development costs 6,165 
Revisions of previous quantity estimates (12,660)
Accretion of discount 17,821 
Net change in income taxes 28,316 
Purchases of reserves in place — 
Sales of reserves in place — 
Changes in timing and other (1,716)
December 31, 2019 $ 53,171 
Sales and transfers of gas and condensate produced, net of production costs (20,211)
Net changes in prices and production costs (58,136)
Extensions, discoveries, additions and improved recovery, net of related costs — 
Development costs incurred — 
Revisions of estimated development costs — 
Revisions of previous quantity estimates 26,133 
Accretion of discount 5,725 
Net change in income taxes 4,077 
Purchases of reserves in place — 
Sales of reserves in place — 
Changes in timing and other (3,874)
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