XML 57 R26.htm IDEA: XBRL DOCUMENT

SUPPLEMENTARY INFORMATION FOR OIL AND GAS PRODUCING ACTIVITIES

12 Months Ended

Dec. 31, 2020

Organization, Consolidation and Presentation of Financial Statements [Abstract]

SUPPLEMENTARY INFORMATION FOR OIL AND GAS PRODUCING ACTIVITIES

SUPPLEMENTARY INFORMATION FOR OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED)

The following supplemental unaudited information regarding the Company’s oil and gas activities is presented pursuant to the disclosure requirements of ASC 932. All oil and gas operations are located in Indonesia.

All of the Company’s operations are directly related to oil and natural gas producing activities from the Kruh Block in Indonesia.

Capitalized Costs Relating to Oil and Gas Producing Activities

SCHEDULE OF CAPITALIZED COSTS

	As of December 31,
	2020			2019
Proved properties
Mineral interests	$	15,084,658		$	15,084,658
Wells, equipment and facilities		5,827,383			5,261,139
Total proved properties		20,912,041			20,345,797

Unproved properties
Mineral interests		1,113,494			958,133
Uncompleted wells, equipment and facilities		-			-
Total unproved properties		1,113,494			958,133

Less accumulated depletion and impairment		(19,573,054	)		(18,918,311	)
Net Capitalized Costs	$	2,452,481		$	2,385,619

Costs Incurred in Oil and Gas Property Exploration, and Development

Amounts reported as costs incurred include both capitalized costs for exploration and development activities and costs charged to expense for normal maintenance operational activities under TAC and KSO of Kruh Block. Exploration costs presented below include the costs of drilling and equipping successful and unsuccessful exploration wells during the year, geological and geophysical expenses, and the costs of retaining undeveloped leaseholds. Development costs include the costs of drilling and equipping development wells, and construction of related production facilities.

	Years Ended December 31,
	2020		2019		2018
GWN (Kruh)
Exploration	$	-	$	-	$	-
Development		566,244		245,202		166,871
	$	566,244	$	245,202	$	166,871

HNE (Citarum)
Exploration	$	155,362	$	142,207	$	64,056
Development		-		-		-
	$	155,362	$	142,207	$	64,056
GWN (Rangkas)
Exploration	$	4,943	$	276,810	$	87,306
Development		-		-		-
	$	4,943	$	276,810	$	87,306

Results of Operations from Oil and Gas Producing Activities

Results of operations for producing activities consist of all activities within the operating reporting segment. Revenues are generated from entitlement of Oil & Gas Property –Kruh Block Proven and profit sharing of the sale of the crude oil under the TAC and KSO. Production costs are costs to operate and maintain the Company’s wells, related equipment, and supporting facilities used in oil and gas operations, including expenditures made and obligations incurred in the exploration, development, extraction, production, transportation, marketing, abandonment and site restoration; and production-related general and administrative expense. The results of operations exclude general office overhead and interest expense attributable to oil and gas activities.

	Years Ended December 31,
	2020			2019			2018
Oil and gas revenues	$	1,980,773		$	4,183,354		$	5,856,341
Production costs		(2,017,856	)		(2,474,230	)		(2,540,353	)
Depletion, depreciation, and amortization		(698,851	)		(876,676	)		(1,156,494	)
Result of oil and gas producing operations before income taxes	$	(735,934	)	$	832,448		$	(2,159,494	)
Provision for income taxes		-			-			-
Results of oil and gas producing operations	$	(735,934	)	$	832,448		$	(2,159,494	)

Proved Reserves the Company Expects to Lift in Kruh Block

The Company’s proved oil reserves have not been estimated or reviewed by independent petroleum engineers. The estimate of the proved reserves for the Kruh Block was prepared by IEC representatives, a team consisting of engineering, geological and geophysical staff based on the definitions and disclosure guidelines of the United States Securities and Exchange Commission (SEC) contained in Title 17, Code of Federal Regulations, Modernization of Oil and Gas Reporting, Final Rule released January 14, 2009 in the Federal Register (SEC regulations).

The Company’s estimates of the proven reserves are made using available geological and reservoir data as well as production performance data. These estimates are reviewed annually by internal reservoir engineers, and Pertamina, and revised as warranted by additional data. Revisions are due to changes in, among other things, development plans, reservoir performance, TAC and KSO effective period and governmental restrictions.

Kruh Block’s general manager, Mr. Denny Radjawane, and the Company’s chief operating officer, Mr. Charlie Wu, have reviewed the reserves estimate to ensure compliance to SEC guidelines for (1) the appropriateness of the methodologies employed; (2) the adequacy and quality of the data relied upon; (3) the depth and thoroughness of the reserves estimation process; (4) the classification of reserves appropriate to the relevant definitions used; and (5) the reasonableness of the estimated reserve quantities. The estimate of reserves was also reviewed by the Company’s chief business development officer and chief executive officer.

The table below shows the individual qualifications of the Company’s internal team that prepares the reserves estimation:

				Total
Reserve	University			professional		Field of professional experience (years)
Estimation Team*		degree major	Degree level		experience (years)		Drilling & Production	Petroleum Engineering	Production Geology	Reserve Estimation
Charlie Wu		Geosciences	Ph.D.		43		12	-	33	22
Djoko Martianto		Petroleum Engineering	B.S.		42		31	12	-	10
Denny Radjawane		Geophysics	M.S.		30		12	-	20	12
Fransiska Sitinjak		Petroleum Engineering	M.S.		17		7	12	-	8
Yudhi Setiawan		Geology	B.S.		18		12	4	6	3
Oni Syahrial		Geology	B.S.		14		-	-	14	8
Juan Chandra		Geology	B.S.		15		-	-	15	9

The individuals from the reserves estimation team are member of at least one of the following professional associations: American Association of Petroleum Geologists (AAPG), Indonesian Association of Geophysicist (HAGI), Indonesian Association of Geologists (IAGI), Society of Petroleum Engineers (SPE), Society of Indonesian Petroleum Engineers (IATMI) and Indonesian Petroleum Association (IPA).

In a “cost recovery” system, such as the TAC or KSO, in which Kruh Block operates or will operate, the production share and net reserves entitlement to the Company reduces in periods of higher oil price and increases in periods of lower oil price. This means that the estimated net proved reserves quantities are subject to oil price related volatility due to the method in which the revenue is derived throughout the contract period. Therefore, the net proved reserves are estimated based on the revenue generated by the Company according to the TAC and KSO economic models.

As of December 31, 2020 and 2019, the Company estimates that it will be entitled to approximately 43.57% and 42.72% of the revenues from the sales of the crude oil produced throughout the operatorship in Kruh Block. The estimates are based on the extension of the Kruh Block operatorship to May 2030 and the cost recovery balance reset to nil in May 2020.

Following the confirmation of the Kruh Block extension, the Company approved a development plan for a drilling program of 18 Proved Undeveloped Reserves (or PUD) wells, according to the schedule below:

	Unit\Year	2021		2022		2023		Total
Planned PUD wells	Gross well		5		6		7		18
Future wells costs ⁽¹⁾	US$		3,824,061		9,000,000		10,500,000		23,324,061
Total gross PUD added	Bbls		1,299,469		1,219,638		1,551,413		4,070,520
Total net PUD added	Bbls		794,392		745,589		948,410		2,488,391

(1)	Future wells costs are the capital expenditures associated with the new wells costs and do not include other capital expenditures such as production facilities.

For Proved Developed (“PDP”) reserves, as a result of a more effective reservoir management, the Company produced a total of 322,887 bbls for the year ended December 31, 2020, a decrease of 231,898bbls compared to previous year estimates of 2020 production. Such recovery also brings reduction of PDP reserves forecast of 10,879 bbls as the revision of previous estimates for future production as of December 31, 2020. However, the net PDP was increase of 21,938 bbls due to the loss of net share (43.57%) from the non-shareable oil (NSO) of 234,116 bbls in the new KSO contract despite the upward revision of net ratio increase (from 42.72% to 43.57%) of beginning total gross PDP and upward revision of PDP reserves estimate in 2020. As a result of rescheduling of development plan, the gross PUD estimate is revised downward by168,461bbls and net PUD estimate is revised downward by 642,170 bbls. No amounts have been incurred during the year ended December 31, 2020 to convert PUD reserves to PDP reserves. Beginning on May 22, 2020, when the Kruh Block operatorship is renewed under the KSO contract, the Company will begin the drilling program to convert PUD reserves to PDP reserves.

The fiscal 2020 and 2019 proved developed and undeveloped reserves are summarized in the tables below:

	Crude Oil (Bbls) as of December 31,
	2020			Note		2019			Note
Total Proved Developed (PDP) and Undeveloped Reserves (PUD)
Beginning of the period		4,619,992					4,997,305
Revisions of previous estimates		(226,585	)		(a)		(290,165	)		(k)
Improved recovery		(11,006	)		(b)		3,841
Purchase of minerals in place		-					-
Extensions and discoveries		-					-
Production		(72,524	)		(c)		(90,989	)		(l)
Sale of minerals in place		-					-
End of the period		4,309,877					4,619,992
Net Proved Developed Reserves (PDP) and Undeveloped Reserves (PUD)
Beginning of the period		1,965,577					2,134,685
Revisions of previous estimates		618,421			(d)		(131,134	)		(m)
Improved recovery		(6,728	)		(e)		1,673
Purchase of minerals in place		-					-
Extensions and discoveries		-					-
Production		(44,335	)		(f)		(39,647	)		(n)
Sale of minerals in place		-					-
End of the period		2,532,934					1,965,577
Total Proved developed reserves (PDP)
Beginning of the period		387,154					398,708
Revisions of previous estimates		(64,267	)		(g)		75,594			(k)
Improved recovery		(11,006	)		(b)		3,841
Purchase of minerals in place		-					-
Extensions and discoveries		-					-
Production		(75,524	)		(c)		(90,989	)		(l)
Sale of minerals in place		-					-
End of the period		239,357					387,154
Total Proved undeveloped reserves (PUD)
Beginning of the period		4,232,838					4,598,597
Revisions of previous estimates		(162,318	)		(h)		(365,759	)		(k)
Improved recovery		-					-
Purchase of minerals in place		-					-
Extensions and discoveries		-					-
Production		-					-
Sale of minerals in place		-					-
End of the period		4,070,521					4,232,838
Net Proved developed reserves (PDP)
Beginning of the period		121,182					170,315
Revisions of previous estimates		(25,576	)		(i)		(11,159	)		(m)
Improved recovery		(6,728	)		(e)		1,673
Purchase of minerals in place		-					-
Extensions and discoveries		-					-
Production		(44,335	)		(f)		(39,647	)		(n)
Sale of minerals in place		-					-
End of the period		44,542					121,182
Net Proved undeveloped reserves (PUD)
Beginning of the period		1,844,395					1,964,370
Revisions of previous estimates		643,997			(j)		(119,975	)		(m)
Improved recovery		-					-
Purchase of minerals in place		-					-
Extensions and discoveries		-					-
Production		-					-
Sale of minerals in place		-					-
End of the period		2,488,392					1,844,395

(a)	The revision of previous estimates in the amount of negative 226,585 bbls refers to the sum of 1) revision of previous PDP reserves estimates of negative 64,267 bbls (g) and 2) revision of previous PUD reserves estimates of negative 162,318 bbls (h);

(b)	The improved recovery amount of negative 11,006 bbls refers to the additional crude oil production compared to previous estimates for Kruh block as a result of an improvement in reservoir management;

(c)	The production of negative 72,524 bbls refers to the amount of total gross crude oil produced from Kruh block in 2020;

(d)	The revision of previous estimates in the amount of 618,421 bbls refers to the total amount of 1) net PDP reserves revision of previous estimates in the amount of negative 25,576 bbls (i) and 2) net PUD reserves revision of previous estimates in the amount of 643,997 bbls (j);

(e)	The improved recovery in the amount of negative 6,728 bbls refers to the net share (61.13%) of crude oil production increase from the Kruh block compared to previous estimates as a result of effective reservoir management;

(f)	The production of negative 44,335 bbls is the amount of net share (61.13%) of the total crude oil production in the amount of negative 72,524 bbls in 2020 (c);

(g)	The revision of previous estimates in the amount of negative 64,267 bbls refers to the total gross amount of PDP reserves increase as a result of improved reservoir management which has increased oil production in 2020;

(h)	The revision of previous estimates in the amount of negative 162,318 bbls refers to the amount of PUD reserves decrease from 2019 to 2020 due to the revision of the drilling schedule;

(i)	The revision of previous estimates of net PDP reserves in the amount of negative 25,576 bbls refers to the sum of 1) net share difference (61.13% in 2020 as compared with 43.57% in 2019) of the beginning total PDP reserves in the amount of 387,154 bbls, 2) net share (61.13%) of revision of previous estimates of total PDP reserves estimates in the amount of negative 64,267 bbls (g), and 3) net share (61.13%) of the transfer of Non-shareable oil (NSO) to Pertamina in the amount of 88,771 bbls according to the KSO contract;

(j)

The revision of previous estimates of net PUD reserves in the amount of 643,997 bbls refers to the sum of 1) net share difference (61.13% in 2020 as compared with 43.57% in 2019) of the beginning total PUD reserves in the amount of 4,232,838 bbls and 2) net share (61.13%) of revision of previous PUD reserves estimates in the amount of negative 162,318 bbls;

(k)	The revision of previous estimates in the amount of negative 290,165 bbls refers to the sum of 1) revision of previous PDP reserves estimates of 75,594 bbls and 2) revision of previous PUD reserves estimates of negative 365,759 bbls;

(l)	The amount of negative 90,989 bbls is the total gross amount of crude oil produced from the Kruh Block in 2019;

(m)	The revision of previous estimates in the amount of negative 131,134 bbls refers to the total amount of 1) net PDP reserves revision of previous estimates in the amount of negative 11,159 bbls and 2) net PUD reserves revision of previous estimates in the amount of negative 119,975 bbls;

(n)	The amount of negative 39,647 bbls is the total net amount of crude oil produced from the Kruh Block in 2019 that the Company is entitled to, calculated as approximately 43.57% of the total gross amount of crude oil produced (m);

Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves

The following information is based on the Company’s best estimate of the required data for the Standardized Measure of Discounted Future Net Cash Flows as of December 31, 2020 and 2019, respectively, in accordance with SFAS No. 69, “Disclosures About Oil and Gas Producing Activities” which requires the use of a 10% discount rate. This information is not the fair market value, nor does it represent the expected present value of future cash flows of the Company’s proved oil and gas reserves.


	As of December 31,
	2020			2019
Future cash inflows	$	100,920,387		$	121,755,908
Future production costs ⁽¹⁾		(43,360,461	)		(46,394,506	)
Future development costs		(41,056,457	)		(41,867,500	)
Future income tax expenses		(5,571,112	)		(15,593,639	)
Future net cash flows	$	10,932,358		$	17,900,262
10% annual discount for estimated timing of cash flows		(5,352,516	)		(7,736,291	)
Standardized measure of discounted future net cash flows at the end of the year	$	5,579,842		$	10,163,971

(1)	Production costs include oil and gas operations expense, production ad valorem taxes, transportation costs and general and administrative expense supporting the Company’s oil and gas operations.

Future cash inflows are computed by applying the ICP previous 12 months average monthly price, to year-end quantities of proved reserves. ICP is determined by the Directorate General of Oil and Gas (“DGOG”) of The Ministry of Energy and Mineral Resources of Indonesia (“MEMR”) on a monthly basis and presented as the monthly price of the crude oil according to the region where the oil is produced. The discounted future cash flow estimates do not include the effects of the Company’s derivative instruments, if any. See the following table for average prices.

SCHEDULE OF AVERAGE PRICES

	Years ended December 31,
	2020		2019		2018
Average crude oil price per Bbl	$	37.58	$	61.89	$	66.12

Future production and development costs, which include abandonment and site restoration expense, are computed by estimating the expenditures to be incurred in developing and producing the Company’s proved crude oil reserves at the end of the year, based on year-end costs, and assuming continuation of existing economic conditions.

Sources of Changes in Discounted Future Net Cash Flows

Principal changes in the aggregate standardized measure of discounted future net cash flows attributable to the Company’s proved crude oil and natural gas reserves at year end are set forth in the table below.


	Year ended December 31,
	2020			2019			2018
Standardized measure of discounted future net cash flows at the beginning of the year	$	10,120,562		$	14,513,446		$	4,222,805
Extensions, discoveries and improved recovery, less related costs		500,000			500,000			(7,000,000	)
Revisions of previous quantity estimates		6,073,161			(3,431,073	)		85,790,320
Changes in estimated future development costs		811,043			752,299			(42,865,000	)
Purchases (sales) of minerals in place		-			-			-
Net changes in prices and production costs		(21,967,808	)		(4,090,493	)		3,655,533	)
Accretion of discount		2,377,063			1,384,269			(8,462,229
Sales of oil and gas produced, net of production costs		(2,536,006	))		(2,166,491	)		(2,946,923	)
Development costs incurred during the period		201,946			245,202			103,337
Change in timing of estimated future production and other		-			-			-
Net change in income taxes		9,999,882			2,413,403			(17,984,397	)
Standardized measure of discounted future net cash flows at the end of the year	$	5,579,842		$	10,120,562		$	14,513,446