Annual report pursuant to Section 13 and 15(d)

SUPPLEMENTAL DISCLOSURES ABOUT NATURAL GAS PRODUCING ACTIVITIES

v3.20.4
SUPPLEMENTAL DISCLOSURES ABOUT NATURAL GAS PRODUCING ACTIVITIES
 12 Months Ended
Dec. 31, 2020
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,
2020 2019 2018
Proved properties $ 62,718  $ 142,494  $ 101,459 
Unproved properties —  —  10,204 
Gross capitalized costs 62,718  142,494  111,663 
Accumulated DD&A (37,639) (21,010) (1,335)
Net capitalized costs $ 25,079  $ 121,484  $ 110,328 
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,
2020 2019 2018
Property acquisitions:
Proved $ 1,307  $ 45,484  $ 13,261 
Unproved —  —  204 
Exploration costs —  —  — 
Development —  800  2,104 
Costs incurred $ 1,307  $ 46,284  $ 15,569 
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,
2020 2019 2018
Natural gas sales $ 30,441  $ 28,774  $ 4,423 
Operating costs 15,814  14,923  11,251 
Depreciation, depletion and amortization 16,703  19,736  1,228 
Impairment charge 81,065  —  2,699 
Total operating costs and expenses 113,582  34,659  15,178 
Results of operations $ (83,141) $ (5,885) $ (10,755)
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, 2020, 2019 and 2018 have been prepared by Netherland, Sewell & Associates, Inc., independent petroleum consultants.
Gas
(MMcf)		 Condensate
(Mbbl)		 Gas Equivalent
(MMcfe)
Proved reserves:
December 31, 2017 327,118  10  327,180 
Extensions, discoveries and other additions 22,481  —  22,481 
Revisions of previous estimates (84,061) (2) (84,072)
Production (1,399) (1) (1,405)
Sale of reserves-in-place —  —  — 
Purchases of reserves-in-place 715  —  715 
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 
Proved developed reserves:
December 31, 2018 17,522  7  17,567 
December 31, 2019 30,699  —  30,699 
December 31, 2020 26,593  —  26,593 
Proved undeveloped reserves:
December 31, 2018 247,332  —  247,332 
December 31, 2019 237,839  —  237,839 
December 31, 2020 72,915  —  72,915 
2019 to 2020 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.
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 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.
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.
2017 to 2018 Changes
•Added approximately 22 Bcfe of proved reserves, comprised primarily of 19 Bcfe from additional proved undeveloped locations as a result of a more detailed analysis from an updated development plan and a 3 Bcfe increase from drilling activities.
•Had negative revisions of approximately 85 Bcfe, comprised primarily of 59 Bcfe as a result of newly acquired 3D seismic data indicating additional geological faulting risks, which led to a reduction in proved undeveloped locations and some lateral lengths, 14 Bcfe, net, from changes in estimating lateral lengths of proved undeveloped locations as a result of more detailed analysis from an updated development plan, and 12 Bcfe due to loss of leases.
•Recorded positive revisions of approximately 1 Bcfe due to an increase in commodity prices.
•Acquired approximately 1 Bcfe of proved reserves through minor interest acquisitions.
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, 2020, 2019 and 2018 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,
2020 2019 2018
Future cash inflows $ 132,563  $ 534,577  $ 676,454 
Future production costs (34,624) (102,268) (105,341)
Future development costs (71,557) (287,111) (264,239)
Future income tax provisions —  (6,612) (54,564)
Future net cash flows 26,382  138,586  252,310 
Less effect of a 10% discount factor (19,497) (85,415) (106,499)
Standardized measure of discounted future net cash flows $ 6,885  $ 53,171  $ 145,811 
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, 2017 $ 88,202 
Sales and transfers of gas and condensate produced, net of production costs (1,773)
Net changes in prices and production costs 27,530 
Extensions, discoveries, additions and improved recovery, net of related costs 13,334 
Development costs incurred 545 
Revisions of estimated development costs 9,663 
Revisions of previous quantity estimates 12,991 
Accretion of discount 11,112 
Net change in income taxes (9,472)
Purchases of reserves in place 844 
Sales of reserves in place — 
Changes in timing and other (7,165)
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