SUPPLEMENTAL DISCLOSURES ABOUT NATURAL GAS PRODUCING ACTIVITIES

12 Months Ended

Dec. 31, 2022

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