May 10, 2022

 

Re:

Kosmos Energy Ltd. (the “Company”) Form 10-K for Fiscal Year Ended December 31, 2021 (“the “Form 10-K”) Filed February 28, 2022 File No. 001-35167

 

Ms. Sandra Wall 

Mr. John Hodgin and 

Mr. Karl Hiller 

Division of Corporate Finance 

Securities and Exchange Commission 

100 F Street N.E. 

Washington, DC 20549-4628

 

Dear Ms. Wall, Mr. Hodgin and Mr. Hiller:

 

This letter is in response to your letter dated April 28, 2022. We have set forth your comments followed by the Company’s response.

 

Form 10-K for the Fiscal Year ended December 31, 2021

 

Business

 

Operations by Geographic Area, page 13

 

1.

Please disclose the average sales price and production cost by geographic area along with the production by final product sold for each country and field that contains 15% or more of your total proved reserves for each of the last three fiscal years. Refer to Item 1204(a) of Regulation S-K and Rule 4-10(a)(15) of Regulation S-X.

 

We have reviewed Item 1204(a) of Regulation S-K and Rule 4-10(a)(15) of Regulation S-X and respectfully acknowledge the Staff’s comment.  We advise the Staff that the Form 10-K included disclosure regarding production by geographic region (including by field) in Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations. We also respectfully advise the Staff that the Form 10-K included disclosure of revenues and production costs by geographic region in Note 17. Business Segment Information. We propose revised disclosure in our future 10-K filings to include the average sales price and production cost by geographic area along with the production by final product sold for each country and field that contains 15% or more of our total proved reserves for each of the last three fiscal years in the Operations by Geographic Area section on page 13. We note oil revenues account for approximately 97%, 98% and 98% of our total revenues for the years ended December 31, 2021, 2020 and 2019, respectively, and, therefore, have combined natural gas and natural gas liquids sales information with our oil sales. We also note that all of our production from Ghana and Equatorial Guinea is oil production, and that the only fields with sales or production within any geographic area or country that contains 15% or more of our total proved reserves over the past 3 years are the Jubilee and TEN fields located offshore Ghana.

 

 

For the fiscal years ended December 31, 2021, 2020 and 2019, this revised tabular disclosure would have been as follows.

 

For the year ended December 31, 2021
Geographic Area/Field		Year-End Estimated Proved Reserves(1)		Percentage of Total Estimated Proved Reserves		Sales Volumes (Net to Kosmos)(3)		Percentage of Sales Volumes		Revenue		Average sales price		Production costs per Boe		Depletion, depreciation and amortization per Boe
		(in MMboe)				(in MMboe)				(in thousands)		(per BOE)
Jubilee		90		30%		7.0		35%		$500,541		$71.21		$11.12		$23.93
TEN		42		14%		2.0		10%		143,691		$73.82		$37.47		$37.30
Ghana(2)		131		44%		9.0		45%		644,232		$71.77		$16.83		$26.84
Equatorial Guinea		27		9%		3.7		19%		260,520		$70.39		$25.13		$15.26
Mauritania/Senegal		106		35%		—		—		—		—		—		—
U.S. Gulf of Mexico		36		12%		7.2		36%		427,261		$59.57		$14.21		$23.44
Total		301		100%		19.9		100%		$1,332,013		$67.10		$17.44		$23.54
Product												(per Bbl/Mcf)
Total Oil (volumes in MMBbl)		185		61%		19.1		96%		$1,313,115		$68.72
Total Gas (volumes in Bcf)		695		38%		4.9		4%		18,898		$3.85
Total (volumes in MMboe)		301		100%		19.9		100%		$1,332,013

 

For the year ended December 31, 2020
Geographic Area/Field		Year-End Estimated Proved Reserves(1)		Percentage of Total Estimated Proved Reserves		Sales Volumes (Net to Kosmos)(4)		Percentage of Sales Volumes		Revenue		Average sales price		Production costs per Boe		Depletion, depreciation and amortization per Boe
		(in MMboe)				(in MMboe)				(in thousands)		(per BOE)
Jubilee		47		34%		6.7		30%		$261,540		$38.84		$14.60		$20.00
TEN		26		19%		3.0		13%		104,975		$35.23		$23.85		$33.81
Ghana		73		53%		9.7		44%		366,515		$37.73		$17.44		$24.27
Equatorial Guinea		27		19%		4.0		18%		152,501		$37.79		$20.02		$16.05
Mauritania/Senegal		—		—		—		—		—		—		—		—
U.S. Gulf of Mexico		39		28%		8.4		38%		285,017		$34.08		$10.56		$21.74
Total		139		100%		22.1		100%		$804,033		$36.36		$15.31		$21.97
Product												(per Bbl/Mcf)
Total Oil (volumes in MMBbl)		127		92%		21.1		96%		$792,327		$37.49
Total Gas (volumes in Bcf)		70		8%		5.9		4%		11,706		$2.00
Total (volumes in MMboe)		139		100%		22.1		100%		$804,033

  

For the year ended December 31, 2019
Geographic Area/Field		Year-End Estimated Proved Reserves(1)		Percentage of Total Estimated Proved Reserves		Sales Volumes (Net to Kosmos)(5)		Percentage of Sales Volumes		Revenue		Average sales price		Production costs per Boe		Depletion, depreciation and amortization per Boe
		(in MMboe)				(in MMboe)				(in thousands)		(per BOE)
Jubilee		57		34%		7.6		30%		$502,499		$66.11		$14.53		$19.60
TEN		38		22%		3.8		15%		236,410		$61.53		$20.23		$31.17
Ghana		95		56%		11.4		46%		738,909		$64.57		$16.45		$23.49
Equatorial Guinea		28		17%		4.7		19%		300,547		$64.19		$19.35		$16.14
Mauritania/Senegal		—		—		—		—		—		—		—		—
U.S. Gulf of Mexico		46		27%		8.8		35%		459,960		$52.23		$14.06		$24.31
Total		169		100%		24.9		100%		$1,499,416		$60.14		$16.15		$22.62
Product												(per Bbl/Mcf)
Total Oil (volumes in MMBbl)		154		91%		23.9		96%		$1,483,817		$62.14
Total Gas (volumes in Bcf)		92		9%		6.3		4%		15,599		$2.47
Total (volumes in MMboe)		169		100%		24.9		100%		$1,499,416

 

 

 

(1)

For information concerning our estimated proved reserves, see “—Our Reserves.” Totals within table may not add a result of rounding.

 

(2)

Our sales volumes during 2021 includes activity related to our acquisition of additional interests in Ghana from October 13, 2021, the acquisition date, through December 31, 2021. Our year-end proved reserves also include the additional interests acquired.

 

(3)

For Jubilee, TEN and Equatorial Guinea, all sales volumes are comprised of oil. Approximately 11% and 7% of the U.S. Gulf of Mexico’s total sales volumes are comprised of natural gas and NGL’s, respectively, which combined represent approximately 7% of total sales volumes for the Company.

 

(4)

For Jubilee, TEN and Equatorial Guinea, all sales volumes are comprised of oil. Approximately 12% and 7% of the U.S. Gulf of Mexico’s total sales volumes are comprised of natural gas and NGL’s, respectively, which combined represent approximately 7% of total sales volumes for the Company.

 

(5)

For Jubilee, TEN and Equatorial Guinea, all sales volumes are comprised of oil. Approximately 12% and 6% of the U.S. Gulf of Mexico’s total sales volumes are comprised of natural gas and NGL’s, respectively, which combined represent approximately 6% of total sales volumes for the Company.

 

Our Reserves

 

Summary of Oil and Gas Reserves, page 21

 

2.

Based on the disclosure in your Results of Operations, there appears to be a significant difference between the average sales price of crude oil/condensate and natural gas liquids. However, we note that you aggregate crude oil/condensate reserves with natural gas liquids reserves here and elsewhere in your disclosure.

 

Please revise the presentation of your reserves to separately disclose the net quantities of your natural gas liquids reserves. If you do not believe separate disclosure is needed, tell us why and augment the disclosure in your filing to provide an explanation.

 

This comment also applies to the disclosure under the Supplemental Oil and Gas Data on page 125. Refer to the disclosure requirements under Items 1202(a)(2) and (a)(4) of Regulation S-K and FASB ASC 932-235-50-4 and 50-5.

 

We respectfully acknowledge the Staff’s comment and advise that sales of natural gas liquids (“NGLs”) for the fiscal years ended December 31, 2021, 2020 and 2019 totaled $14.5 million, $6.2 million and $8.1 million, respectively, as compared to total oil and gas revenues of approximately $1.3 billion, $0.8 billion and $1.5 billion, respectively. Additionally, NGLs represented approximately 1%, 2% and 2% of our total proved reserves and approximately 1%, 1% and 1% of our year-end standardized measure as of December 31, 2021, 2020 and 2019, respectively. As such, we believe that sales of NGLs are immaterial to the Company and, therefore, do not believe it is material to disclose NGLs reserve information separately. We have determined that disclosing sales of NGLs separately in Results of Operations is not consistent with our presentations of reserves elsewhere in the Form 10-K, and in future 10-K filings we propose aggregating sales of NGLs with sales of crude oil to be more consistent.

 

For the fiscal years ended December 31, 2021, 2020 and 2019, this revised tabular disclosure would have been shown as reflected in our response to the Staff’s comment number one above.

 

3.

The footnotes accompanying the disclosure of your proved reserves indicate your natural gas reserves include estimated quantities of natural gas used as fuel in operations. Please disclose the net quantities of fuel gas reserves here and along with your disclosure of proved reserves on page 125. Refer to FASB ASC 932-235-50-10.

 

We respectfully acknowledge the Staff’s comment and advise that the net quantities of fuel gas reserves are included in the Company’s reserves report filed as Exhibit 99.1 to the Form 10-K. We will revise disclosure in our future 10-K filings in both places referenced to specifically include the estimated quantities of natural gas used as fuel in operations.

 

For the fiscal year ended December 31, 2021, this disclosure would have been as follows:

 

(3)

These reserves include the estimated quantity of gas to be exported as LNG from the Greater Tortue Ahmeyim project, as a result of the Tortue SPA finalized in February of 2020. These reserves also include the estimated quantities of fuel gas required to operate the Jubilee and TEN FPSOs and Equatorial Guinea facilities during normal field operations and the associated gas forecasted to be exported from TEN. Total proved natural gas reserves include fuel gas associated with the Jubilee and TEN fields offshore Ghana of approximately 30.0 Bcf, 14.0 Bcf and 18.0 Bcf for 2021, 2020, and 2019, respectively. Our natural gas reserves in Equatorial Guinea are all associated with fuel gas. If and when a subsequent gas sales agreement is executed for Jubilee, a portion of the remaining Jubilee gas may be recognized as reserves. If and when a gas sales agreement and the related infrastructure are in place for the TEN fields non-associated gas, a portion of the remaining gas may be recognized as reserves.

 

(4)

The Mauritania/Senegal Natural Gas reserves presented consists of LNG and approximately 51.0 Bcf of Fuel Gas in our reserve report. We note that the LNG is presented as Plant Products in Mboe in our reserve report.

 

4.

Please expand the footnote explaining the reasons why certain reserves remain undeveloped for five years or more since initial disclosure to identify the individual fields or countries in which these reserves are located. Refer to Item 1203(d) of Regulation S-K.

 

We respectfully acknowledge the Staff’s comment and will revise disclosure in our future 10-K filings to include the reasons why certain reserves remain undeveloped for five years or more since initial disclosure to identify the individual fields or countries in which these reserves are located as required by Item 1203(d) of Regulation S-K.

 

For the fiscal year ended December 31, 2021, this expanded footnote disclosure would have been as follows:

 

(5)

All of our proved undeveloped reserves are expected to be developed within six years or less. Proved undeveloped reserves expected to be developed beyond five years since initial disclosure are all related to the Jubilee and TEN fields offshore Ghana, which are long-term projects which are being developed will be completed under a continuous drilling program.

 

5.

We note that you provide an explanation of the changes that occurred in total proved reserves on pages 21 and 22 for the years ended December 31, 2021, 2020 and 2019. Please provide comparable disclosure in conjunction with the tabular presentation under Supplemental Oil and Gas Data on page 125, as required by FASB ASC 932-235-50-5 and Item 302(b) of Regulation S-K.

 

We respectfully acknowledge the Staff’s comment and advise that the disclosure referred to under Supplemental Oil and Gas Data was summarized from the disclosure explaining the changes that occurred in total proved reserves on pages 21 and 22 for the years ended December 31, 2021, 2020 and 2019. We will revise disclosure in our future 10-K filings to include comparable, un-summarized disclosure in conjunction with the tabular presentation under Supplemental Oil and Gas Data as required by FASB ASC 932-235-50-5 and Item 302(b) of Regulation S-K. For the fiscal year ended December 31, 2021, this disclosure would have appeared as indicated in the proposed language located directly below in response to the Staff’s comment number six.

 

6.

We note that your identification of changes in total proved reserves here and in footnote (2) on page 126 are not consistent with the change categories identified in FASB ASC 932-235-50-5a, 50-5b and 50-5d. As a result, the changes in your discussion cannot be compared directly to the line items in the reconciliation of the changes in reserves presented on page 125, e.g. revisions of previous estimates, improved recovery and extensions and discoveries.

 

Please revise your discussion to align with the change categories in FASB ASC 932-235-50, and as necessary to separately identify and quantify each contributing factor, including offsetting factors, so that changes in net proved reserves between periods are fully explained. The disclosure of revisions in previous estimates in particular should identify the individual changes caused by commodity prices, well performance, unsuccessful and/or uneconomic proved undeveloped locations or the removal of proved undeveloped locations due to changes in a previously adopted development plan.

 

This comment also applies to the discussion of the changes that occurred in your proved undeveloped reserves. Refer to Item 1203(b) of Regulation S-K.

 

We respectfully acknowledge the Staff’s comment and advise that the requested disclosure is included in our Summary of Oil and Gas Reserves on pages 21 and 22. We note that changes in commodity prices may not have material impacts to our reserve changes due to the nature of offshore projects having a significant portion of development costs up front, however, in our future 10-K filings we will include specific disclosure noting the price impacts, if any. We will revise disclosure in our future 10-K filings to include this disclosure elsewhere as requested, and for the fiscal year ended December 31, 2021, this disclosure would have been as follows.

 

	Ghana	Equatorial Guinea	Mauritania / Senegal	U.S. Gulf of Mexico	Total Oil		Ghana	Equatorial Guinea	Mauritania / Senegal	U.S. Gulf of Mexico	Total Gas		Kosmos Total	Equity Method Investment- Equatorial Guinea	Total
	Oil, Condensate, NGLs (MMBbls)						Natural Gas (Bcf)						(MMBoe)
Net proved developed and undeveloped reserves at December 31, 2018(1)	82	—	—	45	127		47	—	—	38	85		141	26	166
Extensions and discoveries	—	—	—	—	—		—	—	—	—	—		—	—	—
Production	(11)	(4)	—	(8)	(23)		(1)	—	—	(6)	(7)		(24)	—	(24)
Revision in estimate(2)	17	6	—	3	26		(1)	(2)	—	3	—		26	—	26
Purchases of minerals-in-place(3)		24	—		24			14	—		14		26	(26)	—
Net proved developed and undeveloped reserves at December 31, 2019(1)	88	26	—	40	154		45	12	—	35	92		169	—	169
Extensions and discoveries(5)	—	—	—	—	—		—	—	600	—	600		100	—	100
Production	(10)	(4)	—	(7)	(21)		—	—	—	(6)	(6)		(22)	—	(22)
Revision in estimate(2)(5)	(10)	2	—	2	(6)		(14)	(1)	(600)	(2)	(617)		(109)	—	(109)
Purchases of minerals-in-place		—	—		—			—	—		—		—	—	—
Net proved developed and undeveloped reserves at December 31, 2020(1)(5)	68	24	—	34	127		31	11	—	27	69		139	—	139
Extensions and discoveries	—	—	—		—		—	—	—	—	—		—	—	—
Production	(10)	(4)	—	(6)	(20)		—	—	—	(5)	(5)		(21)	—	(21)
Revision in estimate(2)	10	4	8	4	26		10	—	590	5	605		127	—	127
Purchases of minerals-in-place(4)	52	—	—	—	52		27	—	—	—	27		57	—	57
Net proved developed and undeveloped reserves at December 31, 2021(1)	120	24	8	32	185		68	11	590	27	695		301	—	301
Proved developed reserves(1)
December 31,2018	48	—	—	33	81		33	—	—	24	57		91	25	116
December 31,2019	47	23	—	34	104		31	12	—	28	71		116	—	116
December 31,2020	26	21	—	32	79		23	11	—	25	60		89	—	89
December 31,2021	52	20	—	28	100		56	11	—	20	87		115	—	115
Proved undeveloped reserves(1)
December 31,2018	33	—	—	12	45		14	—	—	13	28		50	1	51
December 31,2019	41	3	—	6	50		14	—	—	7	21		53	—	53
December 31,2020	42	4	—	2	48		8	—	—	2	10		50	—	50
December 31,2021	68	5	8	4	85		12	—	590	6	608		186	—	186

 

(1)

The sum of proved developed reserves and proved undeveloped reserves may not add to net proved developed and undeveloped reserves as a result of rounding.

 

(2)

The increase in proved reserves is a result of an increase of 9.2 MMBbl in Greater Jubilee related to field performance, positive drilling results and optimization of future development plans. Changes at TEN include a positive revision of 2.0 MMBoe related to increase in estimated associated gas sales. Changes at Equatorial Guinea include an increase of 3.6 MMBbl related to Okume Complex performance and drilling results. Changes at Mauritania/Senegal are related to the economic status of the Greater Tortue Ahmeyim project due to project progress and improved oil price (+106.5 MMBoe). Changes at the U.S. Gulf of Mexico include an increase of 4.4 MMBoe related to strong performance of certain fields.

 

The revisions in estimates in 2021 are related to:  

 

·

upward revision in the Jubilee field offshore Ghana of 8.2 MMBoe due to overall field performance (which includes positive drilling results on proved undeveloped well locations during the year and optimization of future development well locations and completion targets).   Increases in commodity prices during the year resulted in an additional year of production in Jubilee with an associated reserves increase of 1 MMBoe, for an overall field net reserves increase of 9.2 MMBoe.

 

·

upward revision in the TEN fields offshore Ghana of 2.0 MMBoe related to an increase in estimated associated gas sales due to updated reservoir model forecasts that impacted gas production and gas injection forecasts. There was a downward revision of 3.4 MMBoe due to performance of existing wells. Additionally, the increases in commodity prices during the year resulted in adding four years of production to the economic life with an associated benefit of 3.4 MMBoe. The total amount of reserves increase in TEN is 2.0 MMBoe.

 

·

upward revisions in the Okume Complex offshore Equatorial Guinea of 3.0 MMBoe in the Okume Complex due to overall field performance and positive drilling results.  We note that increases in commodity prices during the year resulted in an additional year of production with an associated increase of reserves of 0.7 MMBoe. The total amount of reserves increase in Okume complex is 3.7 MMBoe.

 

·

upward revisions in the Greater Tortue Ahmeyim field offshore Mauritania and Senegal of 106 MMBoe related to the economic status of the project due to the project progress and improved oil price.

 

·

upward revisions in certain fields located in the U.S. Gulf of Mexico of 1.2 MMBoe related to strong performance of certain fields across our portfolio.  Increased commodity prices during the year resulted in a 3.2 MMBoe increase in reserves for a total increase of 4.4 MMBoe.

 

The revisions in estimates in 2020 are related to:  

 

·

downward revision in the Jubilee field offshore Ghana of 0.3 MMBbl related to delayed drilling of water injection wells that will provide needed pressure support to certain production wells. We note that the decreases in commodity prices during the year did not have a material impact to the proved reserves.

 

·

downward revision in the TEN fields offshore Ghana of 5.2 MMBbl related to performance, delayed drilling and alterations to the future development plans. Decreases in commodity prices during the year also had a negative impact of 6.8 MMBoe on reserves for a total negative revision of 12.0 MMBoe.

 

·

upward revisions in the Okume Complex and Ceiba field offshore Equatorial Guinea of 2.0 MMBoe due to overall field performance and positive results from stimulation support.  We note that the decreases in commodity prices during the year did not have a material impact to the proved reserves as both fields’ economic limit did not change from the previous evaluation.

 

·

upward revisions in the Kodiak and Tornado field located in the U.S. Gulf of Mexico of 2.2 MMBoe related to positive drilling results and strong performance.  Commodity price decreases during the year had a negative impact of 0.2 MMBoe for a total revision of 2.0 MMBoe.

 

The revisions in estimates in 2019 are related to: 

 

·

upward revision in the Jubilee field offshore Ghana of 8.2 MMBbl related to positive drilling results and increased estimates in original oil in place and a corresponding optimized development plan.  There were no impacts associated with commodity price changes during the year for these assets.

 

·

upward revision in the TEN fields offshore Ghana of 8.8 MMBbl related to changes in estimates in original oil in place based on updated static modeling and corresponding updates to the development plan.  There were no impacts associated with commodity price changes during the year for these assets.

 

·

upward revisions in the Okume Complex and Ceiba field offshore Equatorial Guinea of 6.3 MMBoe due to production optimization plans and new proved undeveloped drilling locations in the Okume Complex.  There were no impacts associated with commodity price changes during the year for these assets.

 

·

upward revisions in the certain fields located in the U.S. Gulf of Mexico of 2.9 MMBoe related strong performance and the Gladden Deep discovery.  There were no impacts associated with commodity price changes during the year for these assets.

 

(3)

The purchases of minerals-in-place during 2019 are related to We disclosed our share of reserves that were accounted for by the equity method. Effective as of January 1, 2019, our outstanding shares in KTIPI were transferred to Trident in exchange for a 40.4% undivided participating interest in the Ceiba Field and Okume Complex. As a result, our interest in the Ceiba Field and Okume Complex is accounted for under the proportionate consolidation method of accounting going forward.

 

(4)

The purchases of minerals-in-place during 2021 is related to our recent acquisition of additional interests in the Jubilee field and TEN fields offshore Ghana, resulting in reserve additions of 39.9 MMboe and 16.2 MMBOE, respectively.

 

(5)

The Tortue Phase 1 SPA was signed on February 11, 2020, resulting in approximately 100 MMBoe of proved undeveloped reserves being recognized at that time as evaluated by the Company's independent reserve auditor, Ryder Scott, LP. Due to the decrease in commodity prices during 2020 and the related commodity price utilized to calculate proved reserves for SEC purposes, the field did not have proved reserves recognition as of December 31, 2020.

 

Internal Controls Over Reserves Estimation Process, page 24

 

7.

Please refer to the requirements in Item 1202(a)(7) of Regulation S-K and expand the discussion of your internal controls to disclose the qualifications of the technical person that oversees the “Reservoir Engineering team” responsible for the preparation of your reserves estimates.

 

We have reviewed Item 1202(a)(7) of Regulation S-K and we respectfully acknowledge the Staff’s comment. We will revise disclosure in our future 10-K filings to include the qualifications of the technical person that oversees our Reservoir Engineering team responsible for the preparation of our reserves estimates.

 

For the fiscal year ended December 31, 2021, this disclosure would have been as follows:

 

In our Reservoir Engineering team, we maintain an internal staff of petroleum engineering and geoscience professionals with significant experience that contribute to our internal reserve and resource estimates. This team works closely with our independent petroleum engineers to ensure the integrity, accuracy and timeliness of data furnished in their reserve and resource estimation process. Our Reservoir Engineering team is responsible for overseeing the preparation of our reserves estimates and has over 100 combined years of industry experience among them with positions of increasing responsibility in engineering and evaluations. Each member of our team holds a minimum of a Bachelor of Science degree in petroleum engineering or geology. The person primarily responsible for our Reservoir Engineering team is Mr. Douglas Trumbauer. Mr. Trumbauer is a Licensed Professional Engineer in the State of Texas (No. 78735) and has over 35 years of practical experience in petroleum engineering. He graduated from Pennsylvania State University in 1985 with a Bachelor of Science degree in Petroleum and Natural Gas Engineering. Mr. Trumbauer worked for DeGolyer and MacNaughton for 20 years prior to joining Kosmos Energy, and we believe he is proficient in applying industry standard practices to engineering and geoscience evaluations as well as understanding and applying SEC and other industry reserves definitions and guidelines.

 

Gross and Net Undeveloped and Developed Acreage, page 25

 

8.

Please expand your disclosure to provide the expiration dates and acreage amounts for material concentrations of your undeveloped acreage by geographic area. Refer to the disclosure requirements in Item 1208(b) of Regulation S-K.

 

We have reviewed Item 1208(b) of Regulation S-K and respectfully acknowledge the Staff’s comment. We believe that our disclosure in the Exploration License and Lease Areas section on page 15 meets the intent as it includes expiration dates for all of our material concentrations of undeveloped acreage broken out for our exploration licenses by geographic area. We will revise disclosure in our future 10-K filings to also include this expiration information from the Exploration License and Lease Areas section on page 15 in the Gross Net Undeveloped and Developed Acreage table on page 25.

 

Supplemental Oil and Gas Data (Unaudited)

 

Standardized Measure of Discounted Future Net Cash Flows, page 127

 

9.

Please expand the discussion accompanying the presentation of the standardized measure to clarify, if true, that all estimated future costs to settle your asset retirement obligations have been included in your calculation of the standardized measure for each period presented. Refer to the disclosure requirements in FASB ASC 932-235-50-36.

 

We respectfully acknowledge the Staff’s comment and advise that all estimated future costs to settle our asset retirement obligations have been included in our calculation of the standardized measure for each period presented. We will revise disclosure in our future 10-K filings to make this point clear.

 

For the fiscal year ended December 31, 2021, this additional disclosure would have been as follows:

 

	Ghana		Equatorial Guinea		Mauritania / Senegal		U.S. Gulf of Mexico		Total
	(In millions)
At December 31, 2021
Future cash inflows	$      8,308		$      1,661		$         4,314		$       1,981		$          16,264
Future production costs	(2,079)		(621)		(2,853)		(334)		(5,887)
Future development and abandonment costs	(1,640)		(478)		(822)		(284)		(3,224)
Future tax expenses	(1,546)		(307)		(43)		(117)		(2,013)
Future net cash flows	3,043		255		596		1,246		5,140
10% annual discount for estimated timing of cash flows	(983)		37		(671)		(262)		(1,879)
Standardized measure of discounted future net cash flows	$      2,060		$          292		$             (75)		$          984		$            3,261

 

10.

If the estimated future costs to settle your asset retirement obligations (including the costs related to your proved undeveloped reserves) have not been included, tell us the dollar amounts, both undiscounted and discounted at ten percent, for each of the periods presented. Explain to us your rationale for excluding these costs from your calculation of the standardized measure, or revise your disclosure to include these costs.

 

We respectfully acknowledge the Staff’s comment and advise that, in light of our response to the SEC’s comment number nine above, the Staff’s comment number 10 is not applicable.

 

To the extent that you have any questions regarding the response contained in this letter, please do not hesitate to contact me at (214) 445-9600.

 

	Sincerely,
	/s/ Neal D. Shah
	Neal D. Shah
	Senior Vice President and Chief Financial Officer

 

cc:

Andy Inglis Byron B. Rooney, Esq.