Annual report pursuant to Section 13 and 15(d)

SUPPLEMENTAL DISCLOSURES ABOUT NATURAL GAS PRODUCING ACTIVITIES

v3.19.3.a.u2
SUPPLEMENTAL DISCLOSURES ABOUT NATURAL GAS PRODUCING ACTIVITIES
12 Months Ended
Dec. 31, 2019
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,
 
2019
 
2018
 
2017
Proved properties
$
142,494

 
$
101,459

 
$
90,869

Unproved properties

 
10,204

 
13,000

Gross capitalized costs
142,494

 
111,663

 
103,869

Accumulated DD&A
(21,010
)
 
(1,335
)
 
(149
)
Net capitalized costs
$
121,484

 
$
110,328

 
$
103,720


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,
 
2019
 
2018
 
2017
Property acquisitions:
 
 
 
 
 
Proved
$
45,484

 
$
13,261

 
$
90,869

Unproved

 
204

 
13,000

Exploration costs

 

 

Development
800

 
2,104

 
949

Costs incurred
$
46,284

 
$
15,569

 
$
104,818


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,
 
2019
 
2018
 
2017
Natural gas sales
$
28,774

 
$
4,423

 
$
503

Operating costs
14,923

 
11,251

 
1,668

Depreciation, depletion and amortization
19,736

 
1,228

 
115

Impairment charge

 
2,699

 

Total operating costs and expenses
34,659

 
15,178

 
1,783

Results of operations
$
(5,885
)
 
$
(10,755
)
 
$
(1,280
)

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, 2019, 2018 and 2017 have been prepared by Netherland, Sewell & Associates, Inc., independent petroleum consultants.
 
Gas
(MMcf)
 
Condensate
(Mbbl)
 
Gas Equivalent
(MMcfe)
Proved reserves:
 
 
 
 
 
December 31, 2016

 

 

Extensions, discoveries and other additions

 

 

Revisions of previous estimates

 

 

Production
(190
)
 

 
(191
)
Sale of reserves-in-place

 

 

Purchases of reserves-in-place
327,308

 
10

 
327,371

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

Proved developed reserves:
 
 
 
 
 
December 31, 2017
5,720

 
10

 
5,782

December 31, 2018
17,522

 
7

 
17,567

December 31, 2019
30,699

 

 
30,699

Proved undeveloped reserves:
 
 
 
 
 
December 31, 2017
321,398

 

 
321,398

December 31, 2018
247,332

 

 
247,332

December 31, 2019
237,839

 

 
237,839


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 4 Bcfe negative revision due to prices, 2 Bcfe negative revision from changes in operating expenses, 9 Bcfe positive revision from well performance and 1 Bcfe positive revision from changes in ownership.
PUD Changes
Converted approximately 29 Bcfe to proved developed.
Added approximately 12 Bcfe from additional proved undeveloped locations.
Had total positive revisions of approximately 8 Bcfe, comprised primarily of: 9 Bcfe positive revision from well performance, 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 3 Bcfe 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.
2016 to 2017 Changes
Acquired 327 Bcfe of reserves in a series of transactions.
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, 2019, 2018 and 2017 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,
 
2019
 
2018
 
2017
Future cash inflows
$
534,577

 
$
676,454

 
$
777,711

Future production costs
(102,268
)
 
(105,341
)
 
(144,991
)
Future development costs
(287,111
)
 
(264,239
)
 
(331,297
)
Future income tax provisions
(6,612
)
 
(54,564
)
 
(52,212
)
Future net cash flows
138,586

 
252,310

 
249,211

Less effect of a 10% discount factor
(85,415
)
 
(106,499
)
 
(161,009
)
Standardized measure of discounted future net cash flows
$
53,171

 
$
145,811

 
$
88,202


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, 2016
$

Sales and transfers of gas and condensate produced, net of production costs
(265
)
Net changes in prices and production costs

Extensions, discoveries, additions and improved recovery, net of related costs

Development costs incurred

Revisions of estimated development costs

Revisions of previous quantity estimates

Accretion of discount

Net change in income taxes
(22,921
)
Purchases of reserves in place
111,388

Sales of reserves in place

Changes in timing and other

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