YPF SOCIEDAD ANONIMA (ifrs-full:DisclosureOfConsolidatedAndSeparateFinancialStatementsExplanatory)

35. SUPPLEMENTAL INFORMATION ON OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED)

The following information is presented in accordance with Accounting Standards Codification (“ASC”) No. 932 “Extractive Activities – Oil and Gas”, as amended by Accounting Standards Update (“ASU”) No. 2010 – 03 “Oil and Gas Reserves. Estimation and Disclosures”, issued by Financial Accounting Standards Board (“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, 2017, 2016 and 2015 was calculated in accordance with the SEC rules and ASC 932, as amended. Accordingly, crude oil prices used to determine reserves were calculated at the beginning of each month, for crude oils of different quality produced by the Group. Consequently, for calculation of our net proved reserves as of December 31, 2017, the Group considered the realized prices for crude oil in the domestic market (which are higher than those that had prevailed in the international market), taking into account the unweighted average price for each month within the twelve-month period ended December 31, 2017. Additionally, since there are no benchmark market natural gas prices available in Argentina, the Group used average realized gas prices during the year to determine its gas reserves.

Notwithstanding the foregoing, commodity prices have declined significantly since 2014. 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 2017

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 2017, 2016 and 2015, by hydrocarbon product.


	2017								2016									2015
Oil and Condensate	Worldwide			Argentina			Other foreign		Worldwide			Argentina			Other foreign			Worldwide			Argentina			Other foreign
	(Millions of barrels)
Consolidated entities
At January 1,		525			525			—		608			607			1			601			600			1
Developed		380			380			—		440			439			1			447			446			1
Undeveloped		145			145			—		168			168			—			154			154			—
Revisions of previous estimates ⁽¹⁾		(71	)		(72	)		—		(75	)		(74	)		(1	)		31			31			(*	)
Extensions and discoveries		19			19			—		45			45			—			44			44			—
Improved recovery		32			33			—		35			35			—			23			23			—
Purchase of minerals in place		—			—			—		2			2			—			—			—			—
Sale of minerals in place		—			—			—		(*	)		(*	)		—			(*	)		(*	)		—
Production for the year ⁽²⁾		(83	)		(83	)		—		(90	)		(90	)		(*	)		(91	)		(91	)		(*	)

At December 31, ⁽³⁾		422			422			—		525			525			—			608			607			1

Developed		286			286			—		380			380			—			440			439			1
Undeveloped		136			136			—		145			145			—			168			168			—
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		—			—			—		—			—			—			—			—			—


	2017						2016						2015
Oil and Condensate	Worldwide		Argentina		Other foreign		Worldwide		Argentina		Other foreign		Worldwide		Argentina		Other foreign
	(Millions of barrels)
Consolidated and Equity-accounted entities
At January 1,
Developed		380		380		—		440		439		1		447		446		1
Undeveloped		145		145		—		168		168		—		154		154		—

Total		525		525		—		608		607		1		601		600		1

At December 31,
Developed		286		286		—		380		380		—		440		439		1
Undeveloped		136		136		—		145		145		—		168		168		—

Total		422		422		—		525		525		—		608		607		1

*	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 2017, 2016 and 2015 includes an estimated approximately 12, 13 and 13 mmbbl, respectively, in respect of royalty payments which are a financial obligation, or are substantially equivalent to a production or similar tax. Equity-accounted entities production of crude oil in respect of royalty payments which are a financial obligation, or are substantially equivalent to a production or similar tax, is not material.

(3)

Proved crude oil reserves of consolidated entities as of December 31, 2017, 2016 and 2015 include an estimated approximately 61, 76 and 88 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. Proved crude oil reserves of equity–accounted entities in respect of royalty payments which are a financial obligation, or are substantially equivalent to a production or similar tax, are not material.


	2017								2016								2015
Natural Gas Liquids	Worldwide			Argentina			Other foreign		Worldwide			Argentina			Other foreign		Worldwide			Argentina			Other foreign
	(Millions of barrels)
Consolidated entities
At January 1,		68			68			—		71			71			—		73			73			—
Developed		53			53			—		56			56			—		53			53			—
Undeveloped		15			15			—		15			15			—		20			20			—
Revisions of previous estimates ⁽¹⁾		4			4			—		5			5			—		9			9			—
Extensions and discoveries		5			5			—		11			11			—		10			10			—
Improved recovery		—			—			—		—			—			—		—			—			—
Purchase of minerals in place		—			—			—		—			—			—		—			—			—
Sale of minerals in place		—			—			—		—			—			—		(3	)		(3	)		—
Production for the year ⁽²⁾		(19	)		(19	)		—		(19	)		(19	)		—		(18	)		(18	)		—

At December 31, ⁽³⁾		58			58			—		68			68			—		71			71			—

Developed		47			47			—		53			53			—		56			56			—
Undeveloped		11			11			—		15			15			—		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		—			—			—		—			—			—		—			—			—


	2017						2016						2015
Natural Gas Liquids	Worldwide		Argentina		Other foreign		Worldwide		Argentina		Other foreign		Worldwide		Argentina		Other foreign
	(Millions of barrels)
Consolidated and Equity-accounted entities
At January 1,
Developed		53		53		—		56		56		—		53		53		—
Undeveloped		15		15		—		15		15		—		20		20		—

Total		68		68		—		71		71		—		73		73		—

At December 31,
Developed		47		47		—		53		53		—		56		56		—
Undeveloped		11		11		—		15		15		—		15		15		—

Total		58		58		—		68		68		—		71		71		—

*	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 2017, 2016 and 2015 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. Equity-accounted entities production of natural gas liquids in respect of royalty payments which are a financial obligation, or are substantially equivalent to a production or similar tax, is not material.

(3)

Proved natural gas liquids reserves of consolidated entities as of December 31, 2017, 2016 and 2015 include an estimated approximately 6, 8 and 14 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. Proved natural gas liquids reserves of equity–accounted entities in respect of royalty payments which are a financial obligation, or are substantially equivalent to a production or similar tax, are not material.


	2017								2016									2015
Natural gas	Worldwide			Argentina			Other foreign		Worldwide			Argentina			Other foreign			Worldwide			Argentina			Other foreign
	(Billions of standard cubic feet)
Consolidated entities
At January 1,		2,923			2,923			—		3,072			3,067			5			3,016			3,011			5
Developed		2,143			2,143			—		2,210			2,205			5			2,267			2,262			5
Undeveloped		780			780			—		862			862			—			749			749			—
Revisions of previous estimates ⁽¹⁾		(161	)		(161	)		—		(110	)		(105	)		(5	)		174			174			(*	)
Extensions and discoveries		313			313			—		371			371			—			520			520			—
Improved recovery		—			—			—		1			1			—			1			1			—
Purchase of minerals in place		12			12			—		165			165			—			—			—			—
Sale of minerals in place		—			—			—		(*	)		(*	)		—			(70	)		(70	)		—
Production for the year ⁽²⁾		(567	)		(567	)		—		(576	)		(576	)		(*	)		(569	)		(569	)		(*	)

At December 31, ^{(3) (4)}		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			—
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		—			—			—		—			—			—			—			—			—


	2017						2016						2015
Natural gas	Worldwide		Argentina		Other foreign		Worldwide		Argentina		Other foreign		Worldwide		Argentina		Other foreign
	(Billions of standard cubic feet)
Consolidated and Equity-accounted entities
At January 1,
Developed		2,143		2,143		—		2,210		2,205		5		2,267		2,262		5
Undeveloped		780		780		—		862		862		—		749		749		—

Total		2,923		2,923		—		3,072		3,067		5		3,016		3,011		5

At December 31,
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

*	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 2017, 2016 and 2015 includes an estimated approximately 64, 60 and 58 bcf, respectively, in respect of royalty payments which are a financial obligation, or are substantially equivalent to a production or similar tax. Equity-accounted entities production of natural gas in respect of royalty payments which are a financial obligation, or are substantially equivalent to a production or similar tax, is not material.

(3)

Proved natural gas reserves of consolidated entities as of December 31, 2017, 2016 and 2015 include an estimated approximately 289, 337 and 329 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. Proved natural gas reserves of equity-accounted entities in respect of royalty payments which are a financial obligation, or are substantially equivalent to a production or similar tax, are not material.

(4)	Proved natural gas reserves of consolidated entities and equity-accounted entities as of December 31, 2017, 2016 and 2015 include an estimated approximately 364, 467 and 635 bcf, respectively, which is consumed as fuel at the field.


	2017								2016									2015
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,		1,113			1,113			—		1,226			1,224			2			1,212			1,210			2
Developed		815			815			—		889			887			2			905			903			2
Undeveloped		298			298			—		337			337			—			307			307			—
Revisions of previous estimates ⁽²⁾		(96	)		(96	)		—		(89	)		(87	)		(2	)		71			70			1
Extensions and discoveries		80			80			—		122			122			—			147			147			—
Improved recovery		32			32			—		35			35			—			23			23			—
Purchase of minerals in place		2			2			—		31			31			—			—			—			—
Sale of minerals in place		—			—			—		(1	)		(1	)		—			(16	)		(16	)		—
Production for the year ⁽³⁾		(202	)		(202	)		—		(211	)		(211	)		—			(211	)		(210	)		(1	)

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


	2017						2016						2015
Oil equivalent ⁽¹⁾	Worldwide		Argentina		Other foreign		Worldwide		Argentina		Other foreign		Worldwide		Argentina		Other foreign
	(Millions of barrels of oil equivalent)
Consolidated and Equity-accounted entities
At January 1,
Developed		815		815		—		889		887		2		905		903		2
Undeveloped		298		298		—		337		337		—		307		307		—

Total		1,113		1,113		—		1,226		1,224		2		1,212		1,210		2

At December 31,
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

*	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 2017, 2016 and 2015 includes an estimated approximately 25, 27 and 26 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. Barrel of oil equivalent production of equity-accounted entities in respect of royalty payments which are a financial obligation, or are substantially equivalent to a production or similar tax, are not material.

(4)

Proved oil equivalent reserves of consolidated entities as of December 31, 2017, 2016 and 2015 include an estimated approximately 119, 144 and 176 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. Proved oil equivalent reserves of equity-accounted entities in respect of royalty payments which are a financial obligation, or are substantially equivalent to a production or similar tax, are not material.

The paragraphs below explain in further detail the most significant changes in our proved reserves during 2017, 2016 and 2015.

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.

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 and San Jorge basin projects.

•

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 occurred 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 reserved 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.

Changes in our estimated proved reserves during 2015

•

Extensions and Discoveries

Wells drilled in unproved reserves and resource areas added approximately 54 mmboe of proved developed reserves (20 mmbbl of crude oil, 2 mmbbl of NGL and 178 bcf of natural gas), and 93 mmboe of proved undeveloped reserves (24 mmbbl of crude oil, 8 mmbbl of NGL and 342 bcf of natural gas).

The 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 and San Jorge basin projects.

•

Improved Recovery

Approximately 23 mmboe of proved reserves were added mainly due to new projects and positive production response. The main contributions came from the Golfo San Jorge basin (8 mmboe proved developed reserves and 5 mmboe proved undeveloped reserves) and the Neuquina basin (5 mmboe proved developed reserves and 3 mmboe proved undeveloped reserves). Minor additions came from the Cuyana and Austral basins.

•

Sales and Acquisitions

As a result of sales and acquisitions, proved reserves declined by 16.3 mmboe (-8.2 mmboe proved developed reserves and -8.1 mmboe proved undeveloped reserves). This reduction in reserves was mainly related to a modification in the joint venture agreement in the Rincón del Mangrullo field. Additionally, in the El Orejano field, a new joint venture resulted in a reduction of proved developed reserves.

•

Revisions of Previous Estimates

During 2015, the Company’s proved reserves were revised upwards by 71 mmboe (31 mmbbl of crude oil, 9 mmbbl of NGL and 175 bcf of natural gas).

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

•

Total liquids and gas production performance was better than expected, resulting in a 56 mmboe (29.3 mmbbl of crude oil, 5.7 mmbbl of NGL and 117 bcf of natural gas) addition to proved developed reserves. The most significant additions came from the Neuquina and Golfo San Jorge basins. The main fields which performed below expectations were in the Austral basin, resulting in these cases in a reduction of proved reserves.

•

Scheduled compression projects and corresponding production forecasts were reviewed according to the reservoir’s current performance and the available compression technology. This revision resulted in a 21 mmboe addition to proved reserves in the Neuquina basin.

•

Approximately 17 mmboe (8.8 mmbbl of crude oil and 47.4 bcf of natural gas) of proved reserves were added as a result of feasibility studies performed to include new projects pursuant to field development plans, mainly in the Golfo San Jorge basin. Proved reserves were also added in the Austral and Neuquina basins.

This was partially offset by:

•

Mainly as a result of the impact of lower average oil prices in 2015 on economics, 21 mmboe (9.4 mmbbl of crude oil and 64.6 bcf of natural gas) of proved reserves were removed. This price reduction primarily affected reserves in the Austral, Golfo San Jorge and Neuquina basins.

•

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 and Golfo San Jorge basins.

Capitalized costs

The following tables set forth capitalized costs, along with the related accumulated depreciation and allowances as of December 31, 2017, 2016 and 2015:


	2017								2016								2015
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		770,461			—		770,461			621,717			—		621,717			451,900			4,312			456,212
Support equipment and facilities		22,171			—		22,171			18,263			—		18,263			16,920			—			16,920
Drilling and work in progress		40,567			—		40,567			36,966			—		36,966			45,715			—			45,715
Unproved oil and gas properties		6,189			558		6,747			4,788			526		5,314			6,473			451			6,924

Total capitalized costs		839,388			558		839,946			681,734			526		682,260			521,008			4,763			525,771
Accumulated depreciation and valuation allowances		(600,086	)		—		(600,086	)		(473,814	)		—		(473,814	)		(327,579	)		(3,811	)		(331,390	)

Net capitalized costs		239,302			558		239,860			207,920			526		208,446			193,429			952			194,381

There is no Group’s share in equity method investees’ capitalized costs during the years ended December 31, 2017, 2016 and 2015.

Costs incurred

The following tables set forth the costs incurred for oil and gas producing activities during the years ended December 31, 2017, 2016 and 2015:


	2017						2016						2015
Consolidated costs incurred	Argentina		Other foreign		Worldwide		Argentina		Other foreign		Worldwide		Argentina		Other foreign		Worldwide
Acquisition of unproved properties		—		—		—		—		—		—		—		—		—
Acquisition of proved properties		154		—		154		2,093		—		2,093		—		—		—
Exploration costs		3,302		149		3,451		2,922		517		3,439		4,029		440		4,469
Development costs		39,039		—		39,039		49,302		25		49,327		44,753		84		44,837

Total costs incurred		42,495		149		42,644		54,317		542		54,859		48,782		524		49,306

There is no Group’s share in equity method investees’ costs incurred during the years ended December 31, 2017, 2016 and 2015.

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.


	2017									2016									2015
Consolidated results of operations	Argentina			Other foreign			Worldwide			Argentina			Other foreign			Worldwide			Argentina			Other foreign			Worldwide
Net sales to unaffiliated parties		521			—			521			18,489			98			18,587			13,812			197			14,009
Net intersegment sales		115,955			—			115,955			95,496			—			95,496			64,191			—			64,191

Total net revenues		116,476			—			116,476			113,985			98			114,083			78,003			197			78,200
Production costs		(69,944	)		—			(69,944	)		(65,823	)		(39	)		(65,862	)		(43,955	)		(89	)		(44,044	)
Exploration expenses		(2,279	)		(168	)		(2,447	)		(3,140	)		(17	)		(3,157	)		(2,342	)		(127	)		(2,469	)
Depreciation and expense for valuation allowances		(45,277	)		—			(45,277	)		(38,036	)		(90	)		(38,126	)		(22,861	)		(148	)		(23,009	)
Impairment of Property, plan and equipment		5,032			—			5,032			(34,943	)		—			(34,943	)		(2,361	)		(174	)		(2,535	)
Other		(2,706	)		—			(2,706	)		(836	)		—			(836	)		(401	)		(56	)		(457	)

Pre-tax income (loss) from producing activities		1,302			(168	)		1,134			(28,793	)		(48	)		(28,841	)		6,083			(397	)		5,686
Income tax expense / benefit		(456	)		59			(397	)		10,434			16			10,450			(2,114	)		79			(2,035	)

Results of oil and gas producing activities		846			(109	)		737			(18,359	)		(32	)		(18,391	)		3,969			(318	)		3,651

There is no Group’s share in equity method investees’ results of operations during the years ended December 31, 2017, 2016 and 2015.

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, 2017, the Group considered the realized prices for crude oil in the domestic market (which are higher than those that had prevailed in the international market), taking into account the unweighted average price for each month within the twelve-month period ended December 31, 2017.

Additionally, since there are no benchmark market natural gas prices available in Argentina, the Group used average realized gas prices during the year ended December 31, 2017.

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 18.599 as of December 31, 2017.

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.


	2017								2016								2015
Consolidated standardized measure of discounted future net cash flows	Argentina			Other foreign		Worldwide			Argentina			Other foreign		Worldwide			Argentina			Other foreign			Worldwide
	Argentina			Other foreign		Worldwide			Argentina			Other foreign		Worldwide			Argentina			Other foreign			Worldwide
Future cash inflows ⁽¹⁾		564,396			—		564,396			669,791			—		669,791			670,085			589			670,674
Future production costs		(349,819	)		—		(349,819	)		(379,757	)		—		(379,757	)		(395,119	)		(331	)		(395,450	)
Future development costs		(128,885	)		—		(128,885	)		(120,862	)		—		(120,862	)		(116,524	)		(10	)		(116,534	)
Future income tax expenses		(2,324	)		—		(2,324	)		(29,956	)		—		(29,956	)		(30,724	)		(70	)		(30,794	)
10% annual discount for estimated timing of cash flows		(16,935	)		—		(16,935	)		(32,805	)		—		(32,805	)		(30,075	)		(56	)		(30,131	)

Total standardized measure of discounted future net cash flows		66,433			—		66,433			106,411			—		106,411			97,643			122			97,765

(1)	For the years ended December 31, 2017, 2016 and 2015, future cash inflows are stated net of the effect of withholdings 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, 2017, 2016 and 2015.

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, 2017, 2016 and 2015:


	2017			2016			2015
Beginning of year		106,412			97,765			99,383
Sales and transfers, net of production costs		(53,759	)		(52,025	)		(52,321	)
Net change in sales and transfer prices, net of future production costs		(74,046	)		(37,336	)		(80,809	)
Changes in reserves and production rates (timing)		15,495			4,385			3,748
Net changes for extensions, discoveries and improved recovery		28,489			40,565			30,956
Net change due to purchases and sales of minerals in place		—			3,234			—
Changes in estimated future development and abandonment costs		(32,052	)		(19,356	)		(28,225	)
Development costs incurred during the year that reduced future development costs		22,475			28,689			24,475
Accretion of discount		9,724			10,652			13,646
Net change in income taxes		25,920			8,522			35,409
Others		17,775			21,316			51,503

End of year		66,433			106,411			97,765

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, 2017, 2016 and 2015.

YPF SOCIEDAD ANONIMA | CIK:0000904851 |

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