35.

SUPPLEMENTAL INFORMATION ON OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED)

The following information is presented in accordance with ASC No. 932 “Extractive Activities – Oil and Gas”, as amended by ASU 2010 – 03 “Oil and Gas Reserves. Estimation and Disclosures”, issued by FASB in January 2010.

Oil and gas reserves

Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible (from a given date forward, from known reservoirs, and under existing economic conditions, operating methods and government regulations) prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within reasonable time. In some cases, substantial investments in new wells and related facilities may be required to recover proved reserves.

Information on net proved reserves as of December 31, 2018, 2017 and 2016 was calculated in accordance with the SEC rules and Financial Accounting Standards Board (“FASB”) Accounting Standards Codification (“ASC”) 932, as amended. Accordingly, crude oil prices used to determine reserves were calculated each month for crude oils of different quality produced by the Company. Consequently, to calculate our net proved reserves as of December 31, 2018, the Company considered the realized prices for crude oil in the domestic market taking into account the effect of export taxes as in effect as of each of the corresponding years (until 2020, in accordance with Decree No. 793/2018). For the years beyond the mentioned periods, the Company considered the unweighted average price of the first-day-of-the-month for each month within the twelve-month period ended December 31, 2018, which refers to the Brent prices adjusted by each different quality produced by the Company.

Additionally, since there are no benchmark market natural gas prices available in Argentina, the Company considered the realized prices in the domestic market according to the SEC and FASB’Ss ASC 932 rules, but also taking into account the effect of certain market regulations set forth mainly during the second half of the year for certain natural gas segments.

Notwithstanding the foregoing, commodity prices have changed significantly since 2016. See “Item 3. Key Information—Risk Factors—Risks Relating to the Argentine Oil and Gas Business and Our Business—Our oil and natural gas reserves are estimates” and “Item 3. Key Information—Risk Factors—Risks Relating to the Argentine Oil and Gas Business and Our Business—Our reserves and production are likely to decline”.

Net reserves are defined as that portion of the gross reserves attributable to the interest of YPF after deducting interests owned by third parties. In determining net reserves, the Group excludes from its reported reserves royalties due to others, whether payable in cash or in kind, where the royalty owner has a direct interest in the underlying production and is able to make lifting and sales arrangements independently. By contrast, to the extent that royalty payments required to be made to a third party, whether payable in cash or in kind, are a financial obligation, or are substantially equivalent to a production or severance tax, the related reserves are not excluded from the reported reserves despite the fact that such payments are referred to as “royalties” under local rules. The same methodology is followed in reporting our production amounts.

Gas reserves exclude the gaseous equivalent of liquids expected to be removed from the gas on concessions and leases, at field facilities and at gas processing plants. These liquids are included in net proved reserves of natural gas liquids.

Technology used in establishing proved reserves additions in 2018

YPF’s estimated proved reserves are based on estimates generated through the integration of available and appropriate data, utilizing well-established technologies that have been demonstrated in the field to yield repeatable and consistent results. Data used in these integrated assessments include information obtained directly from the subsurface via wellbore, such as well logs, reservoir core samples, fluid samples, static and dynamic pressure information, production test data, and surveillance and performance information. The data utilized also include subsurface information obtained through indirect measurements, including high quality 2-D and 3-D-seismic data, calibrated with available well control. Where applicable, geological outcrops information was also utilized. The tools used to interpret and integrate all these data included both proprietary and commercial software for reservoir modeling, simulation and data analysis. In some circumstances, where appropriate analog reservoir models are available, reservoir parameters from these analog models were used to increase the reliability of our reserves estimates.

Changes in YPF’s Estimated Net Proved Reserves

The table below sets forth information regarding changes in YPF’s net proved reserves during 2018, 2017 and 2016, by hydrocarbon product.


	2018								2017								2016
Oil and Condensate	Worldwide			Argentina			Other foreign		Worldwide			Argentina			Other foreign		Worldwide			Argentina			Other foreign
	(Millions of barrels)
Consolidated entities
At January 1,		422			422			—		525			525			—		608			607			1
Developed		286			286			—		380			380			—		440			439			1
Undeveloped		136			136			—		145			145			—		168			168			—
Revisions of previous estimates ⁽¹⁾		126			126			—		(71	)		(72	)		—		(75	)		(74	)		(1	)
Extensions and discoveries		103			103			—		19			19			—		45			45			—
Improved recovery		15			15			—		32			33			—		35			35			—
Purchase of minerals in place		—			—			—		—			—			—		2			2			—
Sale of minerals in place		(1	)		(1	)		—		—			—			—		(*	)		(*	)		—
Production for the year ⁽²⁾		(83	)		(83	)		—		(83	)		(83	)		—		(90	)		(90	)		(*	)

At December 31, ⁽³⁾		582			582			—		422			422			—		525			525			—

Developed		339			339			—		286			286			—		380			380			—
Undeveloped		243			243			—		136			136			—		145			145			—
Equity-accounted entities
At January 1,		—			—			—		—			—			—		—			—			—
Developed		—			—			—		—			—			—		—			—			—
Undeveloped		—			—			—		—			—			—		—			—			—
Revisions of previous estimates ⁽¹⁾		—			—			—		—			—			—		—			—			—
Extensions and discoveries		—			—			—		—			—			—		—			—			—
Improved recovery		—			—			—		—			—			—		—			—			—
Purchase of minerals in place		—			—			—		—			—			—		—			—			—
Sale of minerals in place		—			—			—		—			—			—		—			—			—
Production for the year ⁽²⁾		—			—			—		—			—			—		—			—			—

At December 31, ⁽³⁾		—			—			—		—			—			—		—			—			—

Developed		—			—			—		—			—			—		—			—			—
Undeveloped		—			—			—		—			—			—		—			—			—
Consolidated and Equity-accounted entities
At January 1,
Developed		286			286			—		380			380			—		440			439			1
Undeveloped		136			136			—		145			145			—		168			168			—

Total		422			422			—		525			525			—		608			607			1

At December 31,
Developed		339			339			—		286			286			—		380			380			—
Undeveloped		243			243			—		136			136			—		145			145			—

Total		582			582			—		422			422			—		525			525			—

*	Not material (less than 1)

(1)	Revisions in estimates of reserves are performed at least once a year. Revision of oil and gas reserves is considered prospectively in the calculation of depreciation.

(2)	Crude oil production for the years 2018, 2017 and 2016 includes an estimated approximately 12, 12 and 13 mmbbl, respectively, in respect of royalty payments which are a financial obligation, or are substantially equivalent to a production or similar tax.

(3)

Proved crude oil reserves of consolidated entities as of December 31, 2018, 2017 and 2016 include an estimated approximately 83, 61 and 76 mmbbl, respectively, in respect of royalty payments which, as described above, are a financial obligation, or are substantially equivalent to a production or similar tax.


	2018								2017								2016
Natural Gas Liquids	Worldwide			Argentina			Other foreign		Worldwide			Argentina			Other foreign		Worldwide			Argentina			Other foreign
	(Millions of barrels)
Consolidated entities
At January 1,		58			58			—		68			68			—		71			71			—
Developed		47			47			—		53			53			—		56			56			—
Undeveloped		11			11			—		15			15			—		15			15			—
Revisions of previous estimates ⁽¹⁾		(1	)		(1	)		—		4			4			—		5			5			—
Extensions and discoveries		13			13			—		5			5			—		11			11			—
Improved recovery		—			—			—		—			—			—		—			—			—
Purchase of minerals in place		—			—			—		—			—			—		—			—			—
Sale of minerals in place		—			—			—		—			—			—		—			—			—
Production for the year ⁽²⁾		(14	)		(14	)		—		(19	)		(19	)		—		(19	)		(19	)		—

At December 31, ⁽³⁾		56			56			—		58			58			—		68			68			—

Developed		41			41			—		47			47			—		53			53			—
Undeveloped		15			15			—		11			11			—		15			15			—
Equity-accounted entities
At January 1,		—			—			—		—			—			—		—			—			—
Developed		—			—			—		—			—			—		—			—			—
Undeveloped		—			—			—		—			—			—		—			—			—
Revisions of previous estimates ⁽¹⁾		—			—			—		—			—			—		—			—			—
Extensions and discoveries		—			—			—		—			—			—		—			—			—
Improved recovery		—			—			—		—			—			—		—			—			—
Purchase of minerals in place		—			—			—		—			—			—		—			—			—
Sale of minerals in place		—			—			—		—			—			—		—			—			—
Production for the year ⁽²⁾		—			—			—		—			—			—		—			—			—

At December 31, ⁽³⁾		—			—			—		—			—			—		—			—			—

Developed		—			—			—		—			—			—		—			—			—
Undeveloped		—			—			—		—			—			—		—			—			—
Consolidated and Equity-accounted entities
At January 1,
Developed		47			47			—		53			53			—		56			56			—
Undeveloped		11			11			—		15			15			—		15			15			—

Total		58			58			—		68			68			—		71			71			—

At December 31,
Developed		41			41			—		47			47			—		53			53			—
Undeveloped		15			15			—		11			11			—		15			15			—

Total		56			56			—		58			58			—		68			68			—

*	Not material (less than 1)

(1)	Revisions in estimates of reserves are performed at least once a year. Revision of oil and gas reserves is considered prospectively in the calculation of depreciation.

(2)	Natural gas liquids production for the years 2018, 2017 and 2016 includes an estimated approximately 2, 2 and 2 mmbbl, respectively, in respect of royalty payments which are a financial obligation, or are substantially equivalent to a production or similar tax.

(3)

Proved natural gas liquids reserves of consolidated entities as of December 31, 2018, 2017 and 2016 include an estimated approximately 8, 6 and 8 mmbbl, respectively, in respect of royalty payments which, as described above, are a financial obligation, or are substantially equivalent to a production or similar tax.


	2018								2017								2016
Natural gas	Worldwide			Argentina			Other foreign		Worldwide			Argentina			Other foreign		Worldwide			Argentina			Other foreign
	(Billions of standard cubic feet)
Consolidated entities
At January 1,		2,520			2,520			—		2,923			2,923			—		3,072			3,067			5
Developed		1,850			1,850			—		2,143			2,143			—		2,210			2,205			5
Undeveloped		670			670			—		780			780			—		862			862			—
Revisions of previous estimates ⁽¹⁾		178			178			—		(161	)		(161	)		—		(110	)		(105	)		(5	)
Extensions and discoveries		329			329			—		313			313			—		371			371			—
Improved recovery		—			—			—		—			—			—		1			1			—
Purchase of minerals in place		—			—			—		12			12			—		165			165			—
Sale of minerals in place		(4	)		(4	)		—		—			—			—		(*	)		(*	)		—
Production for the year ⁽²⁾		(542	)		(542	)		—		(567	)		(567	)		—		(576	)		(576	)		—

At December 31, ^{(3) (4)}		2,481			2,481			—		2,520			2,520			—		2,923			2,923			—

Developed		1,915			1,915			—		1,850			1,850			—		2,143			2,143			—
Undeveloped		566			566			—		670			670			—		780			780			—
Equity-accounted entities
At January 1,		—			—			—		—			—			—		—			—			—
Developed		—			—			—		—			—			—		—			—			—
Undeveloped		—			—			—		—			—			—		—			—			—
Revisions of previous estimates ⁽¹⁾		—			—			—		—			—			—		—			—			—
Extensions and discoveries		—			—			—		—			—			—		—			—			—
Improved recovery		—			—			—		—			—			—		—			—			—
Purchase of minerals in place		—			—			—		—			—			—		—			—			—
Sale of minerals in place		—			—			—		—			—			—		—			—			—
Production for the year ⁽²⁾		—			—			—		—			—			—		—			—			—

At December 31, ⁽³⁾		—			—			—		—			—			—		—			—			—

Developed		—			—			—		—			—			—		—			—			—
Undeveloped		—			—			—		—			—			—		—			—			—
Consolidated and Equity-accounted entities
At January 1,
Developed		1,850			1,850			—		2,143			2,143			—		2,210			2,205			5
Undeveloped		670			670			—		780			780			—		862			862			—

Total		2,520			2,520			—		2,923			2,923			—		3,072			3,067			5

At December 31,
Developed		1,915			1,915			—		1,850			1,850			—		2,143			2,143			—
Undeveloped		566			566			—		670			670			—		780			780			—

Total		2,481			2,481			—		2,520			2,520			—		2,923			2,923			—

*	Not material (less than 1)

(1)	Revisions in estimates of reserves are performed at least once a year. Revision of natural gas reserves is considered prospectively in the calculation of depreciation.

(2)	Natural gas production for the years 2018, 2017 and 2016 includes an estimated approximately 61, 64 and 60 bcf, respectively, in respect of royalty payments which are a financial obligation, or are substantially equivalent to a production or similar tax.

(3)

Proved natural gas reserves of consolidated entities as of December 31, 2018, 2017 and 2016 include an estimated approximately 288, 289 and 337 bcf, respectively, in respect of royalty payments which, as described above, are a financial obligation, or are substantially equivalent to a production or similar tax.

(4)	Proved natural gas reserves of consolidated entities as of December 31, 2018, 2017 and 2016 include an estimated approximately 349, 364 and 467 bcf, respectively, which is consumed as fuel at the field.


	2018								2017								2016
Oil equivalent ⁽¹⁾	Worldwide			Argentina			Other foreign		Worldwide			Argentina			Other foreign		Worldwide			Argentina			Other foreign
	(Millions of barrels of oil equivalent)
Consolidated entities
At January 1,		929			929			—		1,113			1,113			—		1,226			1,224			2
Developed		663			663			—		815			815			—		889			887			2
Undeveloped		266			266			—		298			298			—		337			337			—
Revisions of previous estimates ⁽²⁾		157			157			—		(96	)		(96	)		—		(89	)		(87	)		(2	)
Extensions and discoveries		174			174			—		80			80			—		122			122			—
Improved recovery		15			15			—		32			32			—		35			35			—
Purchase of minerals in place		—			—			—		2			2			—		31			31			—
Sale of minerals in place		(2	)		(2	)		—		—			—			—		(1	)		(1	)		—
Production for the year ⁽³⁾		(193	)		(193	)		—		(202	)		(202	)		—		(211	)		(211	)		—

At December 31, ⁽⁴⁾		1,080			1,080			—		929			929			—		1,113			1,113			—

Developed		722			722			—		663			663			—		815			815			—
Undeveloped		358			358			—		266			266			—		298			298			—
Equity-accounted entities
At January 1,		—			—			—		—			—			—		—			—			—
Developed		—			—			—		—			—			—		—			—			—
Undeveloped		—			—			—		—			—			—		—			—			—
Revisions of previous estimates ⁽²⁾		—			—			—		—			—			—		—			—			—
Extensions and discoveries		—			—			—		—			—			—		—			—			—
Improved recovery		—			—			—		—			—			—		—			—			—
Purchase of minerals in place		—			—			—		—			—			—		—			—			—
Sale of minerals in place		—			—			—		—			—			—		—			—			—
Production for the year ⁽³⁾		—			—			—		—			—			—		—			—			—

At December 31, ⁽⁴⁾		—			—			—		—			—			—		—			—			—

Developed		—			—			—		—			—			—		—			—			—
Undeveloped		—			—			—		—			—			—		—			—			—
Consolidated and Equity-accounted entities
At January 1,
Developed		663			663			—		815			815			—		889			887			2
Undeveloped		266			266			—		298			298			—		337			337			—

Total		929			929			—		1,113			1,113			—		1,226			1,224			2

At December 31,
Developed		722			722			—		663			663			—		815			815			—
Undeveloped		358			358			—		266			266			—		298			298			—

Total		1,080			1,080			—		929			929			—		1,113			1,113			—

*	Not material (less than 1)

(1)	Volumes of natural gas have been converted to barrels of oil equivalent at 5,615 cubic feet per barrel.

(2)	Revisions in estimates of reserves are performed at least once a year. Revision of crude oil, natural gas liquids and natural gas reserves are considered prospectively in the calculation of depreciation.

(3)

Barrel of oil equivalent production of consolidated entities for the years 2018, 2017 and 2016 includes an estimated approximately 24, 25 and 27 mmboe, respectively, in respect of royalty payments which, as described above, are a financial obligation, or are substantially equivalent to a production or similar tax.

(4)

Proved oil equivalent reserves of consolidated entities as of December 31, 2018, 2017 and 2016 include an estimated approximately 143, 119 and 144 mmboe, respectively, in respect of royalty payments which, as described above, are a financial obligation, or are substantially equivalent to a production or similar tax.

The paragraphs below explain in further detail the most significant changes in our proved reserves during 2018, 2017 and 2016.

Changes in our estimated proved reserves during 2018

Extensions and Discoveries

As a result of wells drilled in unproved reserves and resources areas approximately 25 mmboe of proved developed reserves (8 mmbbl of crude oil, 1 mmbbl of NGL and 92 bcf of natural gas), and 149 mmboe of proved undeveloped reserves (95 mmbbl of crude oil, 12 mmbbl of NGL and 238 bcf of natural gas) were added mainly due to new shale oil and gas projects from Loma La Lata Norte, Loma Campana, Bandurria Sur and La Amarga Chica fields.

Main proved undeveloped reserves additions are related to Unconventional and Tight Gas activities in the Neuquina basin, while proved developed reserves contributions come in most cases from the Neuquina, Noroeste and San Jorge basin projects.

Improved Recovery

A total of approximately 15 mmboe of proved reserves were added mainly due to new projects and positive production response. Main contributions come from Golfo San Jorge basin addition was 4.4 mmboe of proved developed and 8 mmboe of proved undeveloped secondary recovery reserves and 3 mmboe from Neuquina basin.

Sales and Acquisitions

As a net result of Sales and Acquisitions, 1.4 mmboe of proved developed reserves were reduced. These reserves decrease is related mainly to the change in participation for Cerro Bandera and Bandurria Sur fields and acquisition of participation in Llancanelo field.

Revisions of Previous Estimates

During 2018, the Company’s proved reserves were revised upwards by 156 mmboe (126 mmbbl of crude oil and 178 bcf of natural gas and a decrease of 1 mmbbl of NGL).

The main revisions to proved reserves have been due to the following:

• As a result of 2018 higher average oil and gas prices and lower operating costs, its impact on incomes, and on fields economic limit, 143 mmboe of Proved Developed Reserves were added. Changes occured mainly in fields of Neuquina Basin (56 mmboe), Golfo San Jorge basin (40 mmboe) and Austral Basin (31 mmboe).

• New economic scenario also improved scheduled projects economics, resulting in a 48 mmboe Proved Undeveloped Reserves incorporation mainly from oil fields of Golfo San Jorge Basin (33 mmboe) and Neuquina basin (15 mmboe).

• Total liquids and gas production performance from existing wells was better than expected, resulting in an addition of approximately 33 mmboe to proved developed reserves, according to new reserves estimates, mainly in the Neuquina and Golfo San Jorge basins.

• Change of development strategy in certain areas which resulted in a downwards revision of 43 mmboe from previous projects mainly from Neuquina, Austral, and Golfo San Jorge basins.

• Same primary and improved recovery oil projects development schedules were modified or canceled, resulting in 5 mmboe proved undeveloped reserves reduction, mainly in Austral, Golfo San Jorge and Cuyana basins.

• Changes in gas compression projects which resulted in a 5 mmboe reduction of proved undeveloped reserves, mainly from Neuquina basin

• Net production results and forecasts from existing and new wells were lower than expected, resulting in a 13 mmboe reduction of proved reserves. Main differences were found in Nequina basin.

Changes in our estimated proved reserves during 2017

Extensions and Discoveries

As a result of wells drilled in unproved reserves and resources areas approximately 26 mmboe of proved developed reserves (7,4 mmbbl of crude oil, 1,9 mmbbl of NGL and 94 bcf of natural gas), and 54 mmboe of proved undeveloped reserves (11,7 mmbbl of crude oil, 3,4 mmbbl of NGL and 219 bcf of natural gas) were added.

Improved Recovery

A total of approximately 32 mmboe of proved reserves were added mainly due to new projects and positive production response. Main contributions come from Neuquina basin (5,4 mmboe of proved developed and 10 mmboe of proved undeveloped reserves) while Golfo San Jorge basin addition was 5,6 mmboe of proved developed and 9,6 mmboe of proved undeveloped secondary recovery reserves.

Sales and Acquisitions

As a net result of Sales and Acquisitions, 2.3 mmboe of proved developed reserves were added. These reserves increase is related to the change in participation for Aguada de la Arena field.

Revisions of Previous Estimates

During 2017, the Company’s proved reserves were revised downwards by 96 mmboe (71 mmbbl of crude oil and 161 bcf of natural gas and an increase of 4 mmbbl of NGL).

The main revisions to proved reserves have been due to the following:

• As a result of 2017 lower average oil and gas prices and higher operating costs, its impact on incomes, and on fields economic limit, 105 mmboe of Proved Developed Reserves were deducted. Changes occured mainly in fields of Neuquina basin (-60 mmboe, Golfo San Jorge Basin (-25 mmboe) and Cuyana Basin (-14 mmboe).

• New economic scenario also affected scheduled projects economics, resulting in a 20 mmboe Proved Undeveloped Reserves reduction mainly from oil fields of Neuquina basin (-15 mmboe) and Golfo San Jorge Basin (-3 mmboe).

• Total liquids and gas production performance from existing wells was better than expected, resulting in an addition of 25 mmboe to proved developed reserves, according to new reserves estimates. Upward revisions of 48 mmboe are primarily due to better than expected well performance mainly in the Neuquina basin (31 mmboe) and Golfo San Jorge basin (14 mmboe). Downward revisions of approximately 23 mmboe are mainly related to performance updates in certain wells in the Neuquina basin.

• A total volume of 5,6 mmboe of proved reserves was added due to feasibility studies performed to include new projects to field development plans, mainly in Golfo San Jorge basin (3,5 mmboe) and Neuquina basin (2,1 mmboe).

• Net production results and forecasts from some new wells were lower than expected, resulting in a 7 mmboe reduction of proved reserves. Main differences were found in Nequina and Golfo San Jorge basins.

• As a better than expected WO jobs performance, 4.2 mmboe of Proved Reserves were added, mainly in Golfo San Jorge and Neuquina basins.

Changes in our estimated proved reserves during 2016

Extensions and Discoveries

As a result of wells drilled in unproved reserves and resources areas, approximately 42 mmboe of proved developed reserves (15.5 mmbbl of crude oil, 3.8 mmbbl of NGL and 128.8 bcf of natural gas), and 79 mmboe of proved undeveloped reserves (29 mmbbl of crude oil, 7 mmbbl of NGL and 242 bcf of natural gas) were added.

The main proved undeveloped reserves additions are related to non-conventional and tight gas activities in the Neuquina basin, while proved developed reserves contributions are mainly from projects in the Neuquina and Golfo San Jorge basins.

Improved Recovery

A total of approximately 35 mmboe of proved reserves were added, mainly due to new projects and positive production response. The main contributions come from the Golfo San Jorge basin (8 mmboe of proved developed and 17 mmboe of proved undeveloped reserves), while 7 mmboe of proved developed reserves and 2 mmboe of proved undeveloped secondary recovery reserves were added in the Neuquina basin.

Sales and Acquisitions

As a net result of sales and acquisitions, 30.7 mmboe of proved reserves (19.5 mmboe of proved developed reserves and 11.2 mmboe of proved undeveloped reserves) were added. These reserves increases are related mainly to the acquisition of interests in the Río Neuquén and Aguada de la Arena fields.

Revisions of Previous Estimates

During 2016, the Company’s proved reserves were revised downwards by 89 mmboe (75 mmbbl of crude oil and 110 bcf of natural gas and an increase of 5 mmbbl of NGL).

The main revisions to proved reserves were due to the following:

• As a result of a lower average oil price in 2016, its impact on incomes, and on the economic limit of fields, 105 mmboe of proved developed reserves were deducted mainly from oil fields. Changes occurred mainly in the fields of the Golfo San Jorge basin (-40 mmboe), the Neuquina basin (-43 mmboe), the Austral basin (-14 mmboe) and the Cuyana basin (-8 mmboe).

• New economic conditions also affected the economics of scheduled projects, resulting in a 45 mmboe reduction of proved undeveloped reserves, mainly from oil fields of the Golfo San Jorge basin (-16 mmboe), the Neuquina basin (-15 mmboe), the Austral basin (-12 mmboe) and the Cuyana basin (-2 mmboe).

• Total liquids and gas production performance from existing wells was better than expected, resulting in an addition of 68 mmboe to proved developed reserves, according to new reserves estimates. Upward revisions of 80 mmboe are primarily due to better than expected well performance mainly in the Neuquina basin (27 mmboe) and the Golfo San Jorge basin (42 mmboe). Downward revisions of approximately 12 mmboe are mainly related to performance updates in certain wells in the Neuquina basin.

• A total volume of 12 mmboe of proved reserves was added due to feasibility studies performed to include new field development projects, mainly in the Neuquina basin (10 mmboe) and the Golfo San Jorge basin (2 mmboe).

• Net production and forecasts from some new wells were lower than expected, resulting in a 10 mmboe reduction of proved reserves. The main differences were found in the Neuquina, Golfo San Jorge and Austral basins.

Capitalized costs

The following tables set forth capitalized costs, along with the related accumulated depreciation and allowances as of December 31, 2018, 2017 and 2016:


	2018									2017								2016
Consolidated capitalized costs	Argentina			Other foreign			Worldwide			Argentina			Other foreign		Worldwide			Argentina			Other foreign		Worldwide
Proved oil and gas properties
Mineral property, wells and related equipment		1,594,064			—			1,594,064			770,461			—		770,461			621,717			—		621,717
Support equipment and facilities		47,224			—			47,224			22,171			—		22,171			18,263			—		18,263
Drilling and work in progress		80,737			—			80,737			40,567			—		40,567			36,966			—		36,966
Unproved oil and gas properties		14,909			1,241			16,150			6,189			558		6,747			4,788			526		5,314

Total capitalized costs		1,736,933			1,241			1,738,174			839,388			558		839,946			681,734			526		682,260
Accumulated depreciation and valuation allowances		(1,283,840	)		(489	)		(1,284,328	)		(600,086	)		—		(600,086	)		(473,814	)		—		(473,814	)

Net capitalized costs		453,093			752			453,846			239,302			558		239,860			207,920			526		208,446

There is no Group’s share in equity method investees’ capitalized costs during the years ended December 31, 2018, 2017 and 2016.

Costs incurred

The following tables set forth the costs incurred for oil and gas producing activities during the years ended December 31, 2018, 2017 and 2016:


	2018						2017						2016
Consolidated costs incurred	Argentina		Other foreign		Worldwide		Argentina		Other foreign		Worldwide		Argentina		Other foreign		Worldwide
Acquisition of unproved properties		276		—		276		—		—		—		—		—		—
Acquisition of proved properties		166		—		166		154		—		154		2,093		—		2,093
Exploration costs		7,283		381		7,664		3,302		149		3,451		2,922		517		3,439
Development costs		53,553		—		53.553		39,039		—		39,039		49,302		25		49,327

Total costs incurred		61,278		381		61,659		42,495		149		42,644		54,317		542		54,859

There is no Group’s share in equity method investees’ costs incurred during the years ended December 31, 2018, 2017 and 2016.

Results of operations from oil and gas producing activities

The following tables include only the revenues and expenses directly associated with oil and gas producing activities. It does not include any allocation of the interest costs or corporate overhead and, therefore, is not necessarily indicative of the contribution to net earnings of the oil and gas operations.

Differences between these tables and the amounts shown in Note 5 “Segment information”, for the exploration and production business unit, relate to additional operations that do not arise from those properties held by the Group.


	2018									2017									2016
Consolidated results of operations	Argentina			Other Foreign			Worldwide			Argentina			Other foreign			Worldwide			Argentina			Other foreign			Worldwide
Net sales to unaffiliated parties		3,085			—			3,085			521			—			521			18,489			98			18,587
Net intersegment sales		207,480			—			207,480			115,955			—			115,955			95,496			—			95,496

Total net revenues		210,565			—			210,565			116,476			—			116,476			113,985			98			114,083
Production costs		(114,381	)		—			(114,381	)		(69,944	)		—			(69,944	)		(65,823	)		(39	)		(65,862	)
Exploration expenses		(5,185	)		(224	)		(5,409	)		(2,279	)		(168	)		(2,447	)		(3,140	)		(17	)		(3,157	)
Depreciation and expense for valuation allowances		(72,044	)		—			(72,044	)		(45,277	)		—			(45,277	)		(38,036	)		(90	)		(38,126	)
Impairment of Property, plan and equipment		3,265			(365	)		2,900			5,032			—			5,032			(34,943	)		—			(34,943	)
Other		(2,839	)		(168	)		(3,007	)		(2,706	)		—			(2,706	)		(836	)		—			(836	)

Pre-tax income (loss) from producing activities		19,381			(757	)		18,624			1,302			(168	)		1,134			(28,793	)		(48	)		(28,841	)
Income tax expense / benefit		(5,814	)		227			(5,587	)		(456	)		59			(397	)		10,434			16			10,450

Results of oil and gas producing activities		13,567			(530	)		13,037			846			(109	)		737			(18,359	)		(32	)		(18,391	)

There is no Group’s share in equity method investees’ results of operations during the years ended December 31, 2018, 2017 and 2016.

Standardized measure of discounted future net cash flows

The standardized measure is calculated as the excess of future cash inflows from proved reserves less future costs of producing and developing the reserves, future income taxes and a discount factor. Future cash inflows represent the revenues that would be received from production of year-end proved reserve quantities assuming the future production would be sold at the prices used for reserves estimates as of year-end (the “average price”). Accordingly, crude oil prices used to determine reserves were calculated each month, for crude oils of different quality produced by the Group.

For the year ended December 31, 2018, the Company considered the realized prices for crude oil in the domestic market taking into account the effect of export taxes as in effect as of each of the corresponding years (until 2020, in accordance with Decree No. 793/2018). For the years beyond the mentioned periods, the Company considered the unweighted average price of the first-day-of-the-month for each month within the twelve-month period ended December 31, 2018, which refers to the Brent prices adjusted by each different quality produced by the Company.

Future production costs include the estimated expenditures related to production of the proved reserves, plus any production taxes without consideration of future inflation. Future development costs include the estimated costs of drilling development wells and installation of production facilities, plus the net costs associated with dismantling and abandonment of wells, assuming year-end costs continue without consideration of future inflation. Future income taxes were determined by applying statutory rates to future cash inflows less future production costs and less tax depreciation of the properties involved. The present value was determined by applying a discount rate of 10% per year to the annual future net cash flows.

The future cash inflows and outflows in foreign currency have been remeasured at the selling exchange rate of Argentine pesos 37.60 as of December 31, 2018.

The standardized measure does not purport to be an estimate of the fair market value of the Group’s proved reserves. An estimate of fair value would also take into account, among other things, the expected recovery of reserves in excess of proved reserves, anticipated changes in future prices and costs and a discount factor representative of the time value of money and the risks inherent in producing oil and gas.


	2018								2017								2016
Consolidated standardized measure of discounted future net cash flows	Argentina			Other foreign		Worldwide			Argentina			Other foreign		Worldwide			Argentina			Other foreign		Worldwide
Future cash inflows ⁽¹⁾		1,786,896			—		1,786,896			564,396			—		564,396			669,791			—		669,791
Future production costs		(913,980	)		—		(913,980	)		(349,819	)		—		(349,819	)		(379,757	)		—		(379,757	)
Future development costs		(304,448	)		—		(304,448	)		(128,885	)		—		(128,885	)		(120,862	)		—		(120,862	)
Future income tax expenses		(121,388	)		—		(121,388	)		(2,324	)		—		(2,324	)		(29,956	)		—		(29,956	)
10% annual discount for estimated timing of cash flows		(138,847	)		—		(138,847	)		(16,935	)		—		(16,935	)		(32,805	)		—		(32,805	)

Total standardized measure of discounted future net cash flows		308,233			—		308,233			66,433			—		66,433			106,411			—		106,411

(1)	For prices used in future cash inflows see “Oil and Gas Reserves”. For the years ended December 31, 2017 and 2016, future cash inflows are stated net of the effect of withholding on exports until 2017 in accordance with Law No. 26,732

There is no Group’s share in equity method investees’ standardized measure of discounted future net cash flows during the years ended December 31, 2018, 2017 and 2016.

Changes in the standardized measure of discounted future net cash flows

The following table reflects the changes in standardized measure of discounted future net cash flows for the years ended December 31, 2018, 2017 and 2016:


	2018			2017			2016
Beginning of year		66,433			106,411			97,765
Sales and transfers, net of production costs		(62,115	)		(53,759	)		(52,025	)
Net change in sales and transfer prices, net of future production costs		68,651			(74,046	)		(37,336	)
Changes in reserves and production rates (timing)		111,137			15,495			4,385
Net changes for extensions, discoveries and improved recovery		160,784			28,489			40,565
Net change due to purchases and sales of minerals in place		(730	)		—			3,234
Changes in estimated future development and abandonment costs		(71,368	)		(32,052	)		(19,356	)
Development costs incurred during the year that reduced future development costs		39,780			22,475			28,689
Accretion of discount		11,490			9,724			10,652
Net change in income taxes		(80,832	)		25,920			8,522
Others		65,003			17,776			21,316

End of year		308,233			66,433			106,411

There is no Group’s share in equity method investees’ changes in the standardized measure of discounted future net cash flows during the years ended December 31, 2018, 2017 and 2016.