CORRESP 1 filename1.htm

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eni.com

FRANCESCO GATTEI

CHIEF FINANCIAL OFFICER

Direct Telephone (+39)-02-52031014

FRANCESCO ESPOSITO

HEAD OF ACCOUNTING AND FINANCIAL STATEMENTS

Direct Telephone (+39)-02-52061632

Prot. CFO/172/2020/P

September 30, 2020

United States Securities and Exchange Commission

100 F Street N.E., Stop 7010

Washington, D.C. 20549

Attention: H. Roger Schwall

Assistant Director

Office of natural resources

Re:

Eni SpA

Form 20-F for the Fiscal Year Ended December 31, 2019

Filed April 2, 2020

File No. 1-14090

Dear Mr. Schwall:

Thank you for your letter dated September 21, 2020 setting forth the comments from the staff (the “Staff”) of the United States Securities and Exchange Commission on the annual report on Form 20-F of Eni S.p.A. (“Eni”) for the year ended December 31, 2019 (the “Form 20-F”). The information set forth below is submitted in response to your comments.

Business Overview

Exploration and Production

Oil and Gas Properties, Operations and Acreage, page 45

Expand your disclosure to provide the expiration dates of material concentrations of your undeveloped acreage by geographic area as of December 31, 2019. Refer to the disclosure requirements in Items 1208 (b) of Regulation S-K.

Response

We do not expect any material impact on our production and development plans to arise from the expiration dates of our undeveloped acreage. As matter of fact, significant concentrations of undeveloped acreage as of the end of 2019, intending those representing at least 5% of the Company’s total undeveloped acreage, related mainly to exploration properties.

By generally industry practice, exploration permits are short or medium term in nature. As a result, many of our significant exploration permits have short minimum remaining terms. However, when an exploration permit nears expiration, an evaluation is carried out and either the acreage is relinquished or, where activities are ongoing or firmly planned, a renewal process is commenced. In Eni’s experience, the renewal process is generally successful. In various cases, in addition, Eni has the right to renew under the terms of the lease or the concession.

Therefore, we do not believe that disclosing the minimum remaining terms of leases and concessions for our undeveloped acreage would be material for investors.

Supplemental Oil and Gas Information (Unaudited)

Oil and Natural Gas Reserves, page F-152

Expand your disclosure to clarify the extent to which the reserves and production figures presented under this section include natural gas and/or crude oil and condensate volumes consumed in operations to comply with FASB ASC 932-235-50-10.

Response

Please note that on page F-153, where we discuss, among other things, the reporting criteria for proved reserves, we disclose that “oil and gas reserves quantities include [..] (ii) volumes of natural gas used for own consumption”. We believe that is consistent with industry practice.

The volumes of gas consumed in operations are reported in Item 4 of our Annual Report on Form 20-F for the year 2019. On pages 38, 42 and 43, we explain that the difference between produced quantities (page 38: 679 million BOE “barrels-of-oil equivalent”, sum of volumes pertaining to subsidiaries and equity-accounted entities) and quantities of hydrocarbons delivered for sale (page 43: 634 million BOE, sum of volumes pertaining to subsidiaries and equity-accounted entities) consists of volumes of gas consumed in operations.

With reference to the guidance provided in FASB ASC 932-235-50-10, please note that as of December 31, 2019 we did not have any contractual obligations to produce and sell a significant portion of reserves at prices that were substantially below those at which the oil and gas could otherwise be sold in the absence of the contractual obligation. Furthermore, we do not expect unusually high development or lifting costs in our future plans to produce our proved reserves. Finally, in the discussion about our undeveloped proved reserves and amounts that have remained proved undeveloped for five years or more (see page 40 of our 2019 filing), as well as in the discussion of our activities by country of operations (see pages 49-57 of our 2019 filing), it is disclosed to extent to which the development of our reserves depends on building any major pipeline or other major facilities.

In response to the Staff’s comment, to enhance the clarity of the disclosure, we will also add the volumes of gas consumed in operations where we describe the reporting criteria for reserves. For illustration of this future disclosure, the corresponding paragraph of the 2019 Form 20-F would read as follows (additional disclosure highlighted):

Oil and gas reserves quantities include: (i) oil and natural gas quantities in excess of cost recovery which the company has an obligation to purchase under certain PSAs with governments or authorities, whereby the company serves as producer of reserves. Reserves volumes associated with oil and gas deriving from such obligation represent 4%, 4% and 1.6% of total proved reserves as of December 31, 2019, 2018 and 2017, respectively, on an oil equivalent basis; (ii) volumes of natural gas used for own consumption with produced volumes amounting to 245, 235 and 191 BCF in 2019, 2018 and 2017, respectively; (iii) the quantities of hydrocarbons related to the Angola LNG plant.

……

The following table presents yearly changes in estimated proved reserves, developed and undeveloped, of crude oil (including condensate and natural gas liquids) and natural gas as of December 31, 2019, 2018 and 2017.

“………………………………………………………………………………………………………………..

Natural Gas
(billion cubic feet)

2019	Italy			Rest of Europe			North Africa			Egypt			Sub - Saharan Africa			Kazakhstan			Rest of Asia			America			Australia and Oceania			Total
Consolidated subsidiaries
Reserves at December 31, 2018		1,199			320			2,890			5,275			3,506			1,989			1,217			277			651			17,324
of which: developed		980			300			1,447			3,331			1,871			1,846			822			154			452			11,203
undeveloped		219			20			1,443			1,944			1,635			143			395			123			199			6,121
Purchase of Minerals in Place																							7						7
Revisions of Previous Estimates		(310	)		4			267			467			747			79			104			(23	)		(108	)		1,227
Improved Recovery
Extensions and Discoveries					2									78						274			4						358
Production ^(b)		(137	)		(64	)		(419	)		(551	)		(210	)		(99	)		(198	)		(24	)		(36	)		(1,738	)
Sales of Minerals in Place ^(a)														(18	)					(48	)		(1	)					(67	)
Reserves at December 31, 2019		752			262			2,738			5,191			4,103			1,969			1,349			240			507			17,111
Equity-accounted entities
Reserves at December 31, 2019					360			14						310									1,716						2,400
of which: developed					276			14						57									1,716						2,063
undeveloped					84									253															337
Purchase of Minerals in Place					405																								405
Revisions of Previous Estimates					76			1						13									1						91
Improved Recovery
Extensions and Discoveries					(2	)																							(2	)
Production					(67	)		(1	)					(36	)								(69	)					(173	)
Sales of Minerals in Place
Reserves at December 31, 2019					772			14						287									1,648						2,721
Reserves at December 31, 2019		752			1,034			2,752			5,191			4,390			1,969			1,349			1,888			507			19,832
Developed		657			839			1,388			4,777			1,946			1,969			685			1,834			322			14,417
consolidated subsidiaries		657			242			1,374			4,777			1,858			1,969			685			186			322			12,070
equity-accounted entities					597			14						88									1,648						2,347
Undeveloped		95			195			1,364			414			2,444						664			54			185			5,415
consolidated subsidiaries		95			20			1,364			414			2,245						664			54			185			5,041
equity-accounted entities					175									199															374

(a) Includes 17.6 BCF as part of a long-term supply agreement to a state-owned national oil company, whereby the buyer has paid the price without lifting the underlying volume in exercise of the take-or-pay clause because it is very likely that the buyer will not redeem its contractual right to lift (make up) the volume paid.
(b) It includes production volumes of natural gas consumed in operations. Said volumes were 245 BCF in 2019.

Your explanation of the changes in total proved reserves provided on pages 38 and 39 identifies multiple factors impacting your proved reserves as well as both positive and negative changes summed into a single quantity without indicating the specific amount attributable to each factor. For example, the discussion on page 38 discloses the net change resulting from the combination of purchases and sales of proved reserves.

Expand your disclosure to address the overall change in the line item by identifying the specific amount attributable to each factor that resulted in changes in the total net quantities of your proved reserves. Any figures that are net of both positive and negative

factors should be separately identified and quantified such that the changes in each line item are fully explained.

In particular, disclosure relating to revisions in previous estimates should identify the individual underlying factors such as the changes caused by commodity prices, well performance, uneconomic proved undeveloped locations or changes resulting from the removal of proved undeveloped locations due to changes in a previously adopted

development plan.

This comment applies to the disclosure of significant changes in total proved reserves for each line item shown in the reserves reconciliation, other than production, and for each of the periods presented, e.g. the periods ending December 31, 2019, 2018 and 2017, respectively, and to the disclosure of material changes that occurred in proved undeveloped reserves during the current fiscal year provided on page 40. Refer to FASB ASC 932-235-50-5, Item 302(b) of Regulation S-K, and Item 1203(b) of Regulation S-K, respectively.

Response

We acknowledge your comment. Generally, our disclosure practice is to not offset significant positive and negative amounts and changes.

We respectfully observe that the net effect of portfolio transactions in our reserve movements for the year 2019 disclosed on page 38 is necessary for the discussion of a replacement ratio of reserves both reported and on an organic basis i.e. excluding portfolio transactions, which is the measure of performance monitored by the management. Nevertheless, on page 39, sales and purchase of minerals-in-place are disclosed separately for each type of transaction, assets type and for subsidiaries and equity-accounted entities. Also on page 39, as required by FASB ASC 932-235-50-5, changes in proved reserves are commented separately with explanations of significant changes with respect to each of the following factors:

Revisions of previous estimates

Extensions and discoveries

Purchases

Sales

The discussion addressed separately subsidiaries and equity-accounted entities. However, in response to the Staff’s comments, in future filings we will provide further break-downs of the changes in the Company’s proved reserves by disclosing the specific volumes attributable to each factor that resulted in changes in the total net quantities of our proved reserves.

For illustration of this future disclosure, the corresponding paragraphs of the 2019 Form 20-F would read as follows (additional disclosure highlighted):

Pages No. 38-39 of Eni’s Annual Report on Form-20-F for the year 2019

“Eni’s proved reserves as of December 31, 2019 totaled 7,268 mmBOE (liquids 3,601 mmBBL; natural gas 19,832 BCF). Eni’s proved reserves reported an increase of 115 mmBOE, or 1.6%, from December 31, 2018 due to progress made in the year in exploring for and developing new reserves and property acquisitions net of property sales.

……

Eni’s subsidiaries added 548 mmBOE of proved oil and gas reserves in 2019 net of sales and purchase of minerals-in-place. This comprised 236 mmBBL of liquids and 1,525 BCF of natural gas. The breakdown of additions to proved reserves is the following:

(i)

extensions and discoveries were up by 101 mmBOE of which 34 mmBBL of crude oil and 358 BCF of natural gas. The increase of 34 mmBBL in oil reserves were driven for 21 mmBBL by the final investment decisions relating to the Assa North field in Nigeria and the Agogo field in the operated Block 15/06 offshore Angola. The 358 BCF additions to gas reserves were driven for 274 BCF by the final investment decisions made for the projects of Udr-Ghasha in the offshore United Arab Emirates.

(ii)

revisions of previous estimates were up by 459 mmBOE of which 203 mmBBL of crude oil and 1,227 BCF of natural gas. Upward revisions of 747 BCF were reported in Sub-Saharan Africa and were mainly driven by the final investment decision for the expansion of the Bonny liquefaction plant, owned by Nigeria LNG (Eni’s interest 10,4%). Upward revisions of 467 BCF were reported in Egypt due to progress in development activities at the Zohr and other minor projects. Upward revisions of 267 BCF were reported in North Africa and were mainly driven by progress in the development at Berkine North fields in Algeria. Downward revisions of 310 BCF were reported in Italy due to the removal of uneconomical reserves reflecting lower commodity prices.

Upward revisions of proved reserves of crude oil were mainly reported in Kazakhstan for 79 mmBBL and were due to progress in developing the Kashagan and Karachaganak projects. Upward revisions of 37 mmBBL were reported in North Africa mainly due to the development of the Berkine North fields in Algeria and other contributions from Libya. Upward revisions of 46 mmBBL were reported in Sub-Saharan Africa and were driven by progress in development activities in Congo and Angola, while 45 mmBBL of upward revisions in the rest of Asia were due to entitlement effects;

(iii)

purchases of mineral-in-place added 29 mmBBL of crude oil proved reserves in America and mainly related to an investment in the Oooguruk production field in Alaska

	(iv)	sales of minerals-in-place were 29 mmBBL in America and mainly related to the disposal of our entire interest in an asset in Ecuador. Sales of proved reserves of gas were 67 BCF of which the largest amount of 48 BCF was in Asia and mainly related to the farm-out of a 20% interest in the Merakes discovery in Indonesia. In addition, sales

of minerals-in-place include approximately 18 BCF of proved reserves of gas as part of a long-term supply agreement to a state-owned national oil company, whereby the buyer has paid the price without lifting the underlying volume due to the take-or-pay clause, as discussed above.

Eni’s share of equity-accounted entities

Eni’s share of equity-accounted entities added 246 mmBOE of proved oil and gas reserves in 2019 net of sale and purchase minerals-in-place. The breakdown of total additions to proved reserves is the following: (i) revisions of previous estimates added 42 mmBBL of proved reserves of crude oil mainly in the Rest of Europe driven by development activities at the Balder X field in Norway. Upward revisions to proved reserves of natural gas were 91 BCF and were due to the same drivers;

(ii) extensions and discoveries added 6 mmBBL of proved reserves of crude oil in the rest of Europe and were mainly driven by the production start-up of the Trestakk field in Norway;

(iii) purchase of minerals in place were 109 mmBBL of proved reserves of crude oil and 405 BCF of proved reserves of natural gas and were localized in the rest of Europe and mainly explained by the acquisition of ExxonMobil producing and development assets in Norway by our 70%-participated joint venture Var Energi.

Furthermore, we will also provide a discussion relating to each comparative year included in the filing to comply with Item 302(b) of Regulation S-K.

Finally, with respect to the discussion of proved undeveloped reserves we believe that our disclosure of changes and underlying factors is complete and accurate and complies with the guidance of Item 1203 (b). However, in response to the Staff’s comments, in future filings we will provide further break-downs of the changes in the Company’s proved reserves by disclosing the specific volumes attributable to each principal factor that resulted in changes in the total net quantities of our proved reserves.

For illustration of this future disclosure, the corresponding paragraphs of the 2019 Form 20-F would read as follows (Eni’s Annual Report on Form 20-F for the year 2019; Item 4 pg 40):

“

Proved undeveloped reserves

Proved undeveloped reserves as of December 31, 2019 totaled 2,114 mmBOE. At year-end, proved undeveloped reserves of liquids amounted to 1,113 mmBBL, mainly concentrated in Africa and Asia.

Proved undeveloped reserves of natural gas amounted to 5,415 BCF, mainly located in Africa. Proved undeveloped reserves of consolidated subsidiaries amounted to 905 mmBBL of liquids and 5,041 BCF of natural gas. The table below provide a summary of changes in total proved undeveloped reserves for 2019.

Subsidiaries and equity-accounted entities
(mmBOE) 2019
Proved undeveloped reserves as of December 31, 2018	2,309
Transfers to proved developed reserves	(655)
Extensions and discoveries	101
Revisions of previous estimates	327
Purchases of minerals-in-place	44
Sales of minerals-in-place	(12)
Proved undeveloped reserves as of December 31, 2019	2,114

In 2019, total proved undeveloped reserves decreased by 195 mmBOE mainly due to progress made in maturing PUDs to proved developed (655 mmBOE). Additions to PUDs for the year included:

(i)

extensions and discoveries were up by 101 mmBOE of which 34 mmBBL of crude oil and 358 BCF of natural gas. The increase of 34 mmBBL in oil reserves was driven for 21 mmBBL by the final investment decisions relating to the Assa North field in Nigeria and the Agogo field in the operated Block 15/06 offshore Angola. The 358 BCF additions to gas reserves were driven for 274 BCF by the final investment decisions made for the projects of Udr-Ghasha in the offshore United Arab Emirates;

(ii)

revisions of previous estimates added 327 mmBOE of which 120 mmBBL of crude oil and 1,058 BCF of natural gas. Upward revisions of 804 BCF of natural gas were reported in Sub-Saharan Africa and were mainly driven by the final investment decision made for an expansion project at the Bonny liquefaction plant in Nigeria and in Egypt for 397 BCF due to the development activity of the Zohr project. Upward revisions of crude oil reserves of 120 mmBBL were mainly reported in Sub-Saharan Africa and North Africa driven by progress in development activities;

(iii)

purchases (up by 44 mmBOE) mainly related to the Vår Energi acquisition in Norway as discussed above; and

(iv)

sales of minerals-in-place (down by 12 mmBOE) related to minor assets in Norway and the Merakes discovery in Indonesia, as mentioned above.

During 2019, Eni matured 655 mmBOE of proved undeveloped reserves to proved developed reserves due to progress in development activities, production start-ups and project revisions. The main reclassifications to proved developed reserves related to the following fields/projects: Zohr and Nidoco in

North West Egypt, Kashagan in Kazakhstan, Litchendjili in Congo, Ngl Eleme in Nigeria and Area 1 in Mexico.

”

***

We are available to discuss the forgoing with you at your convenience. If you have any questions relating to this letter, please feel free to call the undersigned at +39-02-520-31014 and at +39-02-520-61632.

Very truly yours,

/s/ Francesco Gattei		/s/ Francesco Esposito
Chief Financial Officer		Head of
(Francesco Gattei)		Accounting and Financial Statements
		(Francesco Esposito)