| 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 |
|
|