Annual report pursuant to Section 13 and 15(d)

SUPPLEMENTAL DISCLOSURES ABOUT NATURAL GAS PRODUCING ACTIVITIES

v3.22.4
SUPPLEMENTAL DISCLOSURES ABOUT NATURAL GAS PRODUCING ACTIVITIES
 12 Months Ended
Dec. 31, 2022
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,
2022 2021 2020
Proved properties $ 468,351  $ 113,950  $ 62,718 
Unproved properties —  —  — 
Gross capitalized costs 468,351  113,950  62,718 
Accumulated DD&A (92,423) (48,637) (37,639)
Net capitalized costs $ 375,928  $ 65,313  $ 25,079 
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,
2022 2021 2020
Property acquisitions:
Proved $ 135,974  $ 3,409  $ 1,307 
Unproved —  —  — 
Exploration costs —  —  — 
Development costs 210,546  28,955  — 
Costs incurred $ 346,520  $ 32,364  $ 1,307 
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,
2022 2021 2020
Natural gas sales $ 270,977  $ 51,499  $ 30,441 
Operating costs 53,963  20,576  15,814 
Depreciation, depletion and amortization 43,966  10,998  16,703 
Impairment charge —  —  81,065 
Total operating costs and expenses 97,929  31,574  113,582 
Results of operations $ 173,048  $ 19,925  $ (83,141)
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, 2022, 2021 and 2020 have been prepared by Netherland, Sewell & Associates, Inc., independent petroleum consultants.
Gas
(MMcf)		 Condensate
(Mbbl)		 Gas Equivalent
(MMcfe)
Proved reserves:
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 
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 
Proved developed reserves:
December 31, 2020 26,593  —  26,593 
December 31, 2021 73,927  —  73,927 
December 31, 2022 218,382  —  218,382 
Proved undeveloped reserves:
December 31, 2020 72,915  —  72,915 
December 31, 2021 249,409  —  249,409 
December 31, 2022 226,511  —  226,511 
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.
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.
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, 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 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,
2022 2021 2020
Future cash inflows $ 2,441,930  $ 945,651  $ 132,563 
Future production costs (341,925) (133,909) (34,624)
Future development costs (360,107) (211,836) (71,557)
Future income tax provisions (257,908) (54,401) — 
Future net cash flows 1,481,990  545,505  26,382 
Less effect of a 10% discount factor (445,686) (181,302) (19,497)
Standardized measure of discounted future net cash flows $ 1,036,304  $ 364,203  $ 6,885 
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, 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 
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