Distribution of Hydrocarbon Reserves

77

Hydrocarbon Reserves of Mexico

Distribution of HydrocarbonReserves 66

This basic purpose of this chapter is to describe

the evolution of original volumes and hydrocarbon

reserves in their different categories; proved, prob-

able and possible, that stem from all the activities

carried out during 2008, such as the development of

fields, analyses of the pressure-production behavior

in said fields, reinterpretation of geological models

and exploratory activities, among others.

As regards the variations of original hydrocarbon

reserves through additions, this element is formed

by discoveries and field delineations that are the re-

sult of drilling exploratory and delineation wells, and

therefore, the variations mentioned may be positive

or negative. The second element is obtained from

drilling development wells, thus generating increases

and decreases in hydrocarbon reserves. Finally, the

analysis of pressure-production behavior in fields or

the updating of the geological-geophysical models leads

to increases or decreases in revisions that could influ-

ence the values of the hydrocarbon reserves reported.

The above estimations were made in accordance with

the guidelines issued by the Securities and Exchange

Commission (SEC) of the United States for proved

reserves, while the definitions adopted by the Society

of Petroleum Engineers (SPE), the American Associa-

tion of Petroleum Geologists (AAPG), and the World

Petroleum Council (WPC) were used to evaluate the

probable and possible reserves.

Added to the above, there is the distribution of re-

serves at an integral business unit level. In this regard,

it is important to mention that a new organizational

scheme was set up in Pemex Exploración y Produc-

ción in 2008 when two new integral business units

were incorporated, which in addition to complying

with the task of producing current reserves, they are

also entrusted with the mission of extending fields

discovered through the reserves additions and the

delineation of fields, in order to efficiently ensure the

capture of economic value. Table 6.1 compares the

organization of previous business units in effect since

2003 with the new distribution established last year.

6.1 Northeastern Offshore Region

This region is in the southeast of Mexico and it in-

cludes part of the continental shelf and the Gulf of

Mexico slope. It covers an area of approximately

166,000 square kilometers and is located in na-

tional territorial waters, off the coasts of the states

of Campeche, Yucatán and Quintana Roo. Figure 6.1

shows the geographic location of this region.

Region

Northeastern Offshore

Southwestern Offshore

Northern

2003 2008

CantarellKu-Maloob-Zaap


Abkatún-Pol-Chuc Abkatún-Pol-Chuc

Litoral de Tabasco Holok-TemoaLitoral de Tabasco

Poza Rica-Altamira

Burgos Burgos

Poza Rica-AltamiraAceite Terciario del Golfo

Veracruz VeracruzSouthern

Bellota-JujoCinco PresidentesMacuspanaMuspacSamaria-Luna

Bellota-JujoCinco PresidentesMacuspanaMuspacSamaria-Luna

Table 6.1 Previous and current organizational scheme at Pemex Exploración y Producción.

78

Distribution of Hydrocarbon Reserves

The Northeastern Offshore Region currently has two

integral business units: Cantarell and Ku-Maloob-

Zaap, which administer 25 fields. Figure 6.2 shows

the geographic location of the integral business units.

Eleven of the fields have remaining reserves but are

not in production, Kambesah and Után in the Cantarell

Integral Business Unit, and Ayatsil, Baksha, Kayab,

Nab, Numán, Pit, Pohp, Tson, and Zazil-Ha in the Ku-

Maloob-Zaap Integral Business Unit. 14 fields are in

production, of which 9 are located in the Cantarell

Integral Business Unit, and five are in the Ku-Maloob-

Zaap Integral Business Unit.

In 2008, the region’s oil production was 638.9 million

barrels of crude oil, and the natural gas output was

695.9 billion cubic feet of gas. These volumes account

for 62.5 and 27.5 percent of the national total oil and

natural gas production, respectively.

In 2008, the Northeastern Offshore Region reported an

average daily production of 1.7 million barrels of oil,

and 1,901.3 million cubic feet of natural gas. Further-

more, the Ku-Maloob-Zaap project is gradually increas-

ing its production as a result of the development of the

Maloob and Zaap fields. As in previous years, the Akal

field in the Cantarell complex is still the most important

in the country. In 2008, Akal reported an average daily

production of 0.927 million barrels of oil and 1,576.8

million cubic feet of natural gas, all of which was the

result of the activities aimed at maintaining the recov-

ery factor of the Cantarell project, which especially

included well drilling, workovers and well completion

activities and the continuation of reservoir pressure

maintenance projects through nitrogen injection. Just

as in 2008, and based on the above, it is forecast that

the Northeastern Offshore Region will continue to be

the most important oil producer nationwide.

100 200 300 400 500 Km0

Sonora

Coahuila

DurangoSinaloa

Nayarit

Nuevo León

Zacatecas

San Luis PotosíAguascalientes

Guanajuato

Baja California Sur

Chihuahua

Jalisco

MichoacánColima

Querétaro

Puebla

D.F.México

TlaxcalaMorelos

Guerrero

Yucatán

Hidalgo

Tabasco

Chiapas

Guatemala

Belize

Quintana Roo

Oaxaca

Campeche

United States of America

El Salvador

Honduras

Pacific Ocean

Baja California Norte

Tamaulipas

Veracruz

N

S

W E

Gulf of Mexico

NortheasternOffshoreRegion

Figure 6.1 The Northeastern Offshore Region is located in national territorial waters, off the coasts of Campeche, Yucatán and Quintana Roo.

79


6.1.1 Evolution of Original Volumes in Place

Table 6.2 shows the evolution of the original oil and

natural gas volumes of the Northeastern Off-

shore Region in all the different categories

over the last three years. Consequently, the

proved original volume of oil, as of January

1, 2009, is 54,356.6 million barrels, which is

equal to 36.1 percent of the national volume

for such category and this means an increase

as a result of the exploratory activity, as well

as the delineation and development of the

fields in the region. At a regional level, the

Cantarell Integral Business Unit holds most

of this volume with 36,961.1 million barrels

of oil, that is, 68.0 percent of the region’s

total, which means a slight decrease com-

pared with the previous year as a result of

the development and revision of fields in the

business unit. The Ku-Maloob-Zaap Integral

Business Unit reported 17,395.5 million barrels of oil,

which represents 32.0 percent of the regional volume

and this evidences an increase compared with the pre-

Figure 6.2 Geographic location of the integral business units of the Northeastern Offshore Region.

200 m

100 m

50 m

25 m

500 540 580 620460

2130

2170

2090

2050

Dos BocasFrontera

Cd. del Carmen

Zazil-Ha

Tunich

Cantarell

Pok-1

Maloob

Zaap

KuKutz

Chac

LumBacab

Ixtoc

EkBalam

Gulf of Mexico Ku-Maloob-ZaapIntegral Business Unit

Cantarell IntegralBusiness Unit

Takín-101

Takín

N

S

W E

10 20 30 40 km0

Table 6.2 Historical evolution over the last three years of the original volumes in the Northeastern Offshore Region.

Year Category Crude Oil Natural Gas MMbbl Bcf

2007 Total 63,792.2 26,190.5 Proved 53,417.6 24,172.3 Probable 1,106.7 255.0 Possible 9,268.0 1,763.2



80


vious year that is essentially due to the addition of new

reservoir volumes. The probable original volume of oil

amounted to 5,616.1 million barrels, which represents

6.7 percent of the national total and, in turn, it is an

increase when compared with the previous year. The

highest probable original volume of oil corresponds

to the Ku-Maloob-Zaap Integral Business Unit with

5,322.9 million barrels, that is, 94.8 percent of the

region’s total, as a result of the exploration, delinea-

tion, development and revision activities. Additionally,

the Cantarell Integral Business Unit reported 293.2

million barrels of oil, which represents 5.2 percent of

the region’s total, and an increase over the previous

year that can largely be attributed to the addition of the

Kambesah field. The possible original oil volume was

6,114.9 million barrels, which represents 9.7 percent

of the country’s total volume. The possible original

volume decreased when compared with 2008 due to

field revision and development. The Ku-Maloob-Zaap

Integral Business Unit holds 5,607.9 million barrels in

its fields and the Cantarell Integral Business Unit has

507.0 million barrels.

In reference to the proved original volumes of natural

gas, the Northeastern Offshore Region has 23,981.4

billion cubic feet, which is 13.3 percent of the national

total. This value means a decrease over the amount

reported last year, which was mainly due to delinea-

tion, development and revision. The Cantarell Integral

Business Unit contains 73.3 percent of the original

volume, that is, 17,583.9 billion cubic feet and this

implies a reduction compared with last year, mostly

due to revision, while the Ku-Maloob-Zaap Integral

Business Unit has 6,397.6 billion cubic feet of gas,

which is equal to 26.7 percent of the region’s total

and this points to a slight increase in this business

unit. The probable original volume amounted to 897.3

billion cubic feet of natural gas, which represents an

increase when compared with the previous year. Of

this, 93.5 percent is in the Ku-Maloob-Zaap Integral

Business Unit and 6.5 percent is in the Cantarell Inte-

gral Business Unit. The possible original natural gas

volume decreased when compared with the previous

year, which was the result of field revision and devel-

opment. As of January 1, 2009, the regional figure

was 1,154.3 billion cubic feet of gas, of which 83.1

percent is in the Ku-Maloob-Zaap Integral Business

Unit, while the Cantarell Integral Business Unit holds

the remaining 16.9 percent.

6.1.2 Evolution of Reserves

Figures 6.3 and 6.4 show the variations in crude oil and

natural gas reserves over the last three years. As of

January 1, 2009, the total reserves of the Northeastern

Offshore Region amounted to 11,656.6 million barrels

of crude oil and 4,892.9 billion cubic feet of natural gas.

Proved

Probable

Possible

MMbbl

2007 2008 2009

6,532.0 6,052.8 5,919.3

3,444.73,085.0 2,844.5

2,533.92,799.0 2,892.8

12,510.611,936.8 11,656.6

Figure 6.3 Historical evolution of the remaining crude oil reserves in the Northeastern Offshore Region over the last three years.

Bcf

Proved

Probable

Possible

2007 2008 2009

4,038.8 3,635.6 3,365.8

863.0784.7

631.1

814.9962.4

896.1

5,716.75,382.7

4,892.9

Figure 6.4 Historical evolution of the remain-ing natural gas reserves in the Northeastern Offshore Region over the last three years.

81


The 2P reserves amounted to 8,763.8 million barrels

of crude oil, and 3,996.8 billion cubic feet of natural

gas. Tables 6.3 and 6.4 show the composition of the

2P and 3P reserves, respectively, at an integral busi-

ness unit level in terms of heavy, light and superlight

crude oil, as well as associated and non-associated

gas. It should be noted that the non-associated gas

values include the reserves of gas-condensate, dry

gas and wet gas reservoirs.

The region’s proved reserve as of January 1, 2009

amounts to 5,919.3 million barrels of crude oil, that

is, 56.9 percent of the country’s proved reserves. The

proved natural gas reserve totals 3,365.8 billion cubic

feet, and it accounts for 19.1 percent of the national

reserve.

The developed proved reserve was 4,837.5 million

barrels of crude oil and 2,892.0 billion cubic feet of

natural gas. These figures represent 81.7 and 85.9

percent of the region’s total proved reserve, respec-

tively. The undeveloped proved reserves total 1,081.8

million barrels of crude oil and 473.7 billion cubic feet

of natural gas. These amounts correspond to 18.3 and

14.1 percent of the region’s total proved reserve.

The results obtained in 2008 did not cause substantial

variations in the oil type classification in the region’s

proved reserves; heavy and light oil accounted for

99.1 and 0.9 percent, respectively. As regards natural

gas, 99.6 percent is associated gas and 0.4 percent is

non-associated gas.

The probable oil reserve, as of January 1, 2009, is

estimated at 2,844.5 million barrels of oil, that is, 27.4

percent of the national total, while the probable gas

reserve, which is 631.1 billion cubic feet, equals 3.1

percent of the country’s total.

The possible oil reserve as of January 1, 2009 amounts

to 2,892.8 million barrels of oil, which corresponds to

28.5 percent of the national total. In reference to the

possible natural gas reserve, the figure is 896.1 bil-

lion cubic feet of gas, or 4.0 percent of the country’s

total.

Crude Oil and Natural Gas

The proved oil reserve as of January 1, 2009 increased

by 505.4 million barrels compared with the previous

year. This increase is mostly the result of reclassifying

Table 6.3 Composition of 2P reserves by business unit of the Northeastern Offshore Region.

Crude Oil Natural Gas

Heavy Light Superlight Associated Non-associated Business Unit MMbbl MMbbl MMbbl Bcf Bcf

Total 8,676.2 87.6 0.0 3,981.1 15.7 Cantarell 4,087.0 87.6 0.0 2,260.7 15.7 Ku-Maloob-Zaap 4,589.2 0.0 0.0 1,720.4 0.0

Table 6.4 Composition of 3P reserves by business unit of the Northeastern Offshore Region.



Total 11,569.1 87.6 0.0 4,835.1 57.8 Cantarell 5,570.3 87.6 0.0 2,782.6 57.8 Ku-Maloob-Zaap 5,998.7 0.0 0.0 2,052.5 0.0

82


probable reserves to proved caused by the drilling of

development wells in the Maloob and Zaap fields and

the continuation of pressure maintenance through

nitrogen injection in the Ku field, the delineation of

the Ayatsil field, and the discovery of the Pit field that

jointly total 759.1 million barrels of oil. Additionally, the

decrease of 412.6 million barrels of oil was the result of

the revision of the pressure-production behavior in the

Akal, Sihil and Bacab fields. The Cantarell Integral Busi-

ness Unit holds 50.0 percent of the region’s proved oil

reserve, just like the Ku-Maloob-Zaap Integral Business

Unit. In field terms, the highest proportion of proved

oil reserve is to be found in the Akal field.

Regionally, the remaining proved natural gas reserve

reported a net increase of 426.1 billion cubic feet com-

pared with the previous year. The variation may be

attributed to the revision of the pressure-production

behavior in the Akal and Ixtoc fields, the reclassifica-

tion of probable reserves to proved category due to

development drilling in the Zaap field, the delineation

of the Ayatsil field and the addition of the Kambesah

and Pit fields. All of the above therefore made it pos-

sible to add 418.3 billion cubic feet of natural gas.

Nevertheless, this increase was slightly affected by the

decline of 11.4 billion cubic feet of gas in the Bacab,

Lum and Sihil fields. It should be noted that the Akal

and Ku fields provide 69.4 percent of the regional

reserve. At a business unit level, Cantarell provides

59.2 percent, and Ku-Maloob-Zaap has 40.8 percent

of the region’s proved natural gas reserves.

The probable oil reserve estimated as of January 1,

2009 shows a decrease of 240.5 million barrels of oil,

that is, 7.8 percent less when compared with the previ-

ous year. In particular, there were decreases of 718.3

million barrels of oil in Ku, Maloob and Zaap fields

caused by the reclassification of probable reserves to

proved. These decreases were offset by an increase of

329.6 million barrels of oil in the Ayatsil and Pit fields

as a result of the delineation of the fields, as in the

case of the Ayatsil-DL1 well that found much deeper

water-oil contact than previously considered, in addi-

tion to the exploratory activities that also contributed

to the above increase. It should be noted that 57.2

percent of the region’s probable oil reserve is in the

Ku-Maloob-Zaap Integral Business Unit.

The region’s probable natural gas reserve reported

a decrease of 153.7 billion cubic feet as of January

1, 2009, when compared with January 1, 2008. This

was mostly due to the reclassification of reserves in

the Maloob and Zaap fields. These decreases were

softened by the increases in the Ayatsil, Ixtoc, Kamb-

esah and Pit fields that jointly added 79.8 billion cubic

feet of natural gas. At a business unit level, 55.0 per-

cent of the probable gas reserves are concentrated

in the Ku-Maloob-Zaap Integral Business Unit, with

the remaining 45.0 percent in the Cantarell Integral

Business Unit.

The possible oil reserve as of January 1, 2009 reported

an increase of 93.8 million barrels compared with the

previous year. The delineation of the Ayatsil field, the

development and revision of the Balam field, and

the addition of the Pit field, increased reserves by

408.4 million barrels of oil. Additionally, the decrease

of 165.4 million barrels of oil was the result of the

variation of the pressure-production behavior in the

Akal, Ek, and Maloob fields. The region’s possible oil

reserves are distributed as follows; 51.3 percent in the

Cantarell Integral Business Unit, and 48.7 percent in

the Ku-Maloob-Zaap Integral Business Unit.

As of January 1, 2009, the possible natural gas reserve

declined by 66.4 billion cubic feet when compared

with January 1, 2008, as a result of the revision of the

pressure-production behavior and development in

the Akal, Ek and Maloob fields, that jointly reported a

decrease of 92.5 billion cubic feet of gas. In contrast,

the increase in reserves amounting to 42.5 billion

cubic feet of natural gas in the Ayatsil and Pit fields

due to delineation and addition activities lessened

the above-mentioned decline in reserves. Table 6.5

shows the natural gas reserves by integral business

unit estimated as of January 1, 2009 in the proved,

83


probable and possible categories, as well as the gas

to be delivered to plant and dry gas.

Oil Equivalent

The proved oil equivalent reserve in the Northeastern

Offshore Region as of January 1, 2009 totaled 6,712.3

million barrels. Field exploration, delineation and

development activities, plus field behavior revisions

in 2008, indicate an increase of 377.2 million barrels

of oil equivalent. This variation is mostly associated

with the Ayatsil, Maloob, Pit, and Zaap fields. At an

integral business unit level, Cantarell accounts for

52.2 percent, and Ku-Maloob-Zaap has 47.8 percent.

Figure 6.5 shows the distribution of proved reserves

by business unit.

The probable oil equivalent reserve as of January 1,

2009 was 2,977.1 million barrels, which means 20.5

percent of the country’s reserves. Compared with

January 1, 2008, there was a reduction of 313.1 million

barrels of oil equivalent caused by the reclassification

of probable reserves to proved and possible in the

Ku, Maloob, and Zaap fields. Figure 6.6 shows the

Table 6.5 Distribution of remaining gas reserves by business unit of the Northeastern Off-shore Region as of January 1, 2009.

Category Business Unit Natural Gas Gas to be Dry Gas Delivered to Plant Bcf Bcf Bcf

Proved Total 3,365.8 2,337.7 1,840.4 Cantarell 1,992.2 1,561.8 1,230.5 Ku-Maloob-Zaap 1,373.5 775.9 609.9 Probable Total 631.1 394.2 310.3 Cantarell 284.2 225.7 177.9 Ku-Maloob-Zaap 346.9 168.5 132.4 Possible Total 896.1 585.1 468.9 Cantarell 563.9 451.9 364.2 Ku-Maloob-Zaap 332.2 133.2 104.7

MMboe

Cantarell Ku-Maloob-Zaap

Total

3,501.6

6,712.33,210.7

Figure 6.5 Proved reserves as of January 1, 2009, distributed by business unit in the Northeastern Offshore Region.

MMboe


Total

1,290.3 2,977.1

1,686.8

Figure 6.6 Probable reserves as of January 1, 2009, distributed by business unit in the Northeastern Offshore Region.

84


distribution of probable reserves by business unit;

Ku-Maloob-Zaap accounts for the highest amount

with 56.7 percent of the region’s total.

The possible oil equivalent reserve, as of January 1,

2009, amounted to 3,096.5 million barrels, which is

21.0 percent of the national total. When comparing

this reserve with the figure reported the previous year,

there is a positive variation of 53.6 million barrels of

oil equivalent, which is largely the result of delineation

in the Ayatsil field and the exploratory addition of the

Pit field. As regards the decreases, the Akal, Ek, and

Maloob fields, jointly account for 209.3 million barrels

of oil equivalent due to the revision of the pressure-

production behavior in the case of the former, and

field development in the case of the two last cases.

Figure 6.7 shows the participation of each business

unit in the region’s possible oil equivalent reserves.

It can therefore be seen that 52.9 percent of the total

is in the Cantarell Integral Business Unit.

Figure 6.8 shows the elements of change in the total

or 3P reserve of the Northeastern Offshore Region. As

can be seen, as of January 1 2009, the total regional

reserves amounted to 12,785.9 million barrels of

oil equivalent, which is 29.4 percent of the national

total. There was an increase of 0.9 percent in the

region’s 3P reserve, that is, 117.7 million barrels of

oil equivalent, compared with the figure reported in

the previous year.

Reserve-Production Ratio

The Northeastern Offshore Region produced 689.5

million barrels of oil equivalent during 2008; conse-

quently, the proved reserve-production ratio is 9.7

years. Considering the proved plus probable (2P)

reserve, the reserve-production ratio is 14.1 years and

18.5 years for the proved plus probable plus possible

(3P) reserve.

In particular, the proved reserve-production ratio of

the Cantarell Integral Business Unit is 8.4 years and the

MMboe

Cantarell Ku-Maloob-Zaap

Total

1,637.2

3,096.51,459.3

Figure 6.7 Possible reserves as of January 1, 2009, distributed by business unit in the Northeastern Offshore Region.

Figure 6.8 Elements of change in the total reserve of the Northeastern Offshore Region.

350.2

283.5256.6 Plant Liquids

Condensate

Dry GasEquivalent

Crude Oil

635.4

616.4368.9

589.8

521.0

503.7

795.3 -713.9

36.3 -689.514,086.0

13,357.712,785.9

421.1509.6

696.4

15,193.5

Developments

MMboe

Additions ProductionRevisions

13,566.412,510.6

11,936.8 11,656.6

2007 2008 20092006

85


figure for Ku-Maloob-Zaap is 11.7 years, considering

production volumes of 415.1 and 274.4 million barrels

of oil equivalent, respectively. The production of 1.0

million barrels per day makes the Cantarell Integral

Business Unit the leading oil producer nationwide.

The Ku-Maloob-Zaap Integral Business Unit, however,

showed a proved plus probable (2P) reserve-pro-

duction ratio of 17.8 years, and a reserve-production

ratio of 23.2 years for the proved plus probable plus

possible (3P) reserve. Reservoir development and

pressure maintenance activities through nitrogen

injection are focused on maintaining production at

approximately 800 thousand barrels of oil per day

during the coming years.

Reserves by Fluid Type

Table 6.6 shows the evolution of reserves over the last

three years in the Northeastern Offshore Region by fluid

type, in the proved, probable and possible categories.

The proved reserve is therefore 6,712.3 million barrels

of oil equivalent, of which 88.2 percent is crude oil, 3.8

percent is condensate, 2.7 percent is plant liquids, and

5.3 percent is dry gas equivalent to liquid.

The probable reserve amounts to 2,977.1 million barrels

of oil equivalent. Of this amount, 95.5 percent is crude

oil, 1.4 percent is condensate, 1.0 percent is plant liq-

uids, and 2.0 percent is dry gas equivalent to liquid.

The 3,096.5 million barrels of oil equivalent in the pos-

sible reserve are constituted as follows: 93.4 percent is

crude oil, 2.3 percent is condensate, 1.4 percent is plant

liquids and 2.9 percent is dry gas equivalent to liquid.

6.2 Southwestern Offshore Region

In recent years, the Southwestern Offshore Region

has been characterized by discoveries of significant

volumes of hydrocarbon reserves, and therefore it

helps in the drive to meet reserve replacement rates

at a regional and national level. The region is in territo-

rial waters that include the continental shelf and slope

of the Gulf of Mexico. It covers an area of 352,390

square kilometers. To the south, it is bounded by the

states of Veracruz, Tabasco and Campeche, to the

east it borders on the Northeastern Offshore Region,

and to the north and west; it is limited by the national

territorial waters, as is shown in Figure 6.9.

Table 6.6 Historical evolution of reserves by fluid type in the Northeastern Offshore Region.

Year Category Crude Oil Condensate Plant Dry Gas Total Liquids Equivalent MMbbl MMbbl MMbbl MMboe MMboe

2007 Total 12,510.6 635.4 350.2 589.8 14,086.0 Proved 6,532.0 443.2 254.3 422.7 7,652.2 Probable 3,444.7 103.1 53.5 88.8 3,690.1 Possible 2,533.9 89.1 42.4 78.3 2,743.7 2008 Total 11,936.8 616.4 283.5 521.0 13,357.7 Proved 6,052.8 407.5 200.7 363.6 7,024.6 Probable 3,085.0 98.6 37.9 68.6 3,290.2 Possible 2,799.0 110.3 44.8 88.7 3,042.9

2009 Total 11,656.6 368.9 256.6 503.7 12,785.9 Proved 5,919.3 256.1 183.0 353.9 6,712.3 Probable 2,844.5 42.1 30.9 59.7 2,977.1 Possible 2,892.8 70.7 42.8 90.2 3,096.5

86


As of January 1, 2009, the organization structure con-

sisted of the Abkatún-Pol-Chuc, Litoral de Tabasco, and

Holok-Temoa integral business units. The latter is a re-

cent creation and it was basically established to develop

and administer the fields located in isobaths exceeding

500 meters. Additionally, the Southwestern Offshore

Region has an exploration business unit whose name

was changed from the Regional Exploration Business

Unit to the Plataforma Continental Sur Exploration Busi-

ness Unit. Figure 6.10 shows the geographic location.

The region currently administers 66 fields, 17 of which

produce light and superlight oil and associated gas,

that is, there is a sizeable number of fields still to be

developed. It should be noted that two new fields

have been included in the register of fields, and they

illustrate the positive results of the exploratory work

being done in the region, and they also evidence an

opportunity area to maintain and increase hydrocar-

bon production at a regional and national level.

In 2008, the daily oil and natural gas production in the

region averaged a volume of 500.3 thousand barrels

and 1,022.9 million cubic feet, that is, over the year

there was an accumulation of 183.1 million barrels of

oil and 374.4 billion cubic feet of natural gas, which

means a contribution of 17.9 and 14.8 percent of the

national oil and gas production, respectively.

Last year’s exploratory activity was successful in that

two new fields, Tsimin and Tecoalli, were discovered;

in addition more reservoirs were added in the existing

fields, that is, at a Jurassic level in Xanab and the con-

tribution of new Tertiary sands in the Yaxché field.

6.2.1 Evolution of Original Volumes in Place

The proved original volume of oil in the Southwestern

Offshore Region as of January 1, 2009 was 17,691.1

million barrels, which is equal to 11.7 percent of the

Figure 6.9 The Southwestern Offshore Region is in the continental shelf and slope waters of the Gulf of Mexico.

Sonora

Coahuila

DurangoSinaloa

Nayarit

Nuevo León

Zacatecas


Guanajuato

Baja California Sur

Chihuahua

Jalisco

MichoacánColima

Querétaro

Puebla

D.F.México

TlaxcalaMorelos

Guerrero

Yucatán

Hidalgo

Tabasco

Chiapas

Guatemala

BelizeOaxaca

Campeche


El Salvador

Honduras


Tamaulipas

Veracruz

Gulf of Mexico

Pacific Ocean

N

S

W E

100 200 300 400 500 Km0

Quintana Roo

SouthwesternOffshoreRegion

87


national total volume for such category, and implies an

increase of 6.4 percent when compared with last year.

The Abkatún-Pol-Chuc Integral Business Unit holds

most of the region’s volume with 14,158.1 million bar-

rels of oil, that is, 80.0 percent of the total.

The Litoral de Tabasco Integral Business Unit,

however, has 3,533.0 million barrels of oil,

that is, 20.0 percent of the regional volume,

which means an increase when compared

with the previous year, due to new reservoirs,

developments and revisions. Furthermore,

the newly-created Holok-Temoa Integral Busi-

ness Unit administers the Lakach, Lalail, and

Noxal fields that only contain non-associated

gas reservoirs. The probable and possible

original oil volumes total 3,396.3 and 4,186.0

million barrels, which is equal to 4.0 and 6.6

percent of the national volumes, respectively.

The highest probable original volume of

oil corresponds to the Litoral de Tabasco

Integral Business Unit with 2,147.2 million

barrels, that is, 63.2 percent of the region’s total, as a

result of the exploratory addition of new reservoirs,

and development and revision activities. In contrast,

the Abkatún-Pol-Chuc Integral Business Unit holds

200 m

100 m

50 m

25 m

500 540 580 620460

2130

2170

2090

2050

Dos BocasFrontera

Cd. del Carmen

KaxUechKiAlux

Kab

101A1A

Yum401

301

101

May

Kix

Caan

ManikTaratunich

BolontikuHayabil-1

2-B

Citam

301201

101

Abkatún

Kay

Och Pol

Toloc

Chuc

Ixtal

Batab

Yaxché

Gulf of Mexico

Litoral de TabascoIntegral Business Unit

Holok-TemoaIntegral Business Unit

Abkatún-Pol-ChucIntegral Business Unit

Sinán

Misón

Ayín

N

S

W E

10 20 30 40 km0

Figure 6.10 Geographic location of the integral business units that make up the South-western Offshore Region.

Table 6.7 Historical evolution over the last three years of the original volumes in the Southwestern Offshore Region.


2007 Total 22,799.4 28,763.0 Proved 16,275.3 18,659.7 Probable 2,763.2 3,320.8 Possible 3,761.0 6,782.4



88


36.8 percent of the probable original volume, which

means 1,249.1 million barrels of oil, and which is less

than last year essentially because of the reclassification

of probable reserves to proved due to field develop-

ment. Of the 4,186.0 million barrels in the possible

original volume of crude oil, 3,034.0 million barrels are

located in the fields of the Litoral de Tabasco Integral

Business Unit and 1,152.0 million barrels correspond

to the Abkatún-Pol-Chuc Integral Business Unit. When

compared with those reported as of January 1, 2008,

these figures show an increase in the case of the Litoral

de Tabasco Integral Business Unit, that was largely due

to the addition of new reservoirs through exploratory

activities, and a decrease in the case of Abkatún-Pol-

Chuc caused by field delineation activities.

In reference to the original volumes of natural gas,

as of January 1, 2009, the Southwestern Offshore

Region has 21,615.9 billion cubic feet in the proved

category, which is 11.9 percent of the national total.

This is an increase over what was reported as January

1, 2008. The Abkatún-Pol-Chuc Integral Business Unit

contains 66.9 percent of the regional volume, that is,

14,459.1 billion cubic feet, which is an increment due

to new developments and revisions. There are 6,728.4

billion cubic feet distributed in the Litoral de Tabasco

Integral Business Unit, and it makes up 31.1 percent

of the region’s total. The remaining 2.0 percent is in

the Holok-Temoa Integral Business Unit, specifically

in the Lakach field. The probable original volumes

total 5,439.7 billion cubic feet of natural gas, that is,

there is an increase over the previous year mostly

caused by new reservoirs and reclassification as a

result of developments. 62.4 percent of the probable

original volume corresponds to the Litoral de Tabasco

Integral Business Unit, 20.8 percent is in the Abkatún-

Pol-Chuc Integral Business Unit, and 16.7 percent in

Holok-Temoa. The possible volumes total 6,338.6

billion cubic feet of gas, which means a decrease

when compared with last year that was caused by

delineations. The Litoral de Tabasco Integral Business

Unit accounts for 59.9 percent of the region’s possible

original volume, while the Holok-Temoa fields hold

34.1 percent and the Abkatún-Pol-Chuc fields provide

the remaining 6.1 percent. It is important to mention

that there were significant discoveries in 2008 as a

result of exploratory activities carried out particularly

in the Litoral de Tabasco Integral Business Unit that

led to increases in the original volumes. Table 6.7

shows the behavior of the original oil and natural gas

volumes in their different categories reported as of

January 1, 2007 to 2009.


The proved oil reserve in the Southwestern Offshore

Region as of January 1, 2009 was 1,176.0 million bar-

Proved

Probable

Possible

MMbbl

2007 2008 2009

1,038.0 994.9 1,176.0

744.2 911.9985.5

1,118.8 1,020.91,056.0

2,900.9 2,927.83,217.4

Figure 6.11 Historical evolution of the remain-ing crude oil reserves in the Southwestern Offshore Region over the last three years.

Bcf

Proved

Probable

Possible

2007 2008 2009

2,643.7 2,787.4 3,462.9

1,706.42,214.3

2,675.9

3,611.93,267.6

3,433.07,961.9 8,269.3

9,571.8

Figure 6.12 Historical evolution of the remain-ing natural gas reserves in the Southwestern Offshore Region over the last three years.

89


rels, which is 11.3 percent of the country’s proved

reserves. In reference to the proved reserve of natu-

ral gas, the figure was 3,462.9 billion cubic feet, that

is, 19.6 percent of the total proved reserve of gas

nationwide.

The probable and possible oil reserves inventory to-

taled 985.5 and 1,056.0 million barrels, representing

9.5 and 10.4 percent, respectively, of the national oil

reserves in these categories. Consequently, the 2P

and 3P reserves amounted to 2,161.5 and 3,217.4

million barrels of oil, respectively. F0or natural gas,

the probable and possible reserves are 2,675.9 and

3,433.0 billion cubic feet, which is equal to 13.3 and

15.2 percent of the national total in such categories.

The 2P and 3P reserves therefore amounted to 6,138.8

and 9,571.8 billion cubic feet of natural gas. Figures

6.11 and 6.12 show the variations in the oil and natural

gas reserves over the last three years. In reference to

the developed and undeveloped proved reserves of

the region, the figures show 673.7 and 502.3 million

barrels of crude oil, while the amount for natural gas is

1,604.6 and 1,858.2 billion cubic feet, respectively.

The region’s proved oil reserve consists of 1,176.0

million barrels that are made up, in terms of density,

by 120.9 million barrels of heavy oil or 10.3 percent

of the reserve, 808.2 million barrels of light oil or

68.7 percent, and the remaining 246.9 million barrels

are superlight, which means the latter provides 21.0

percent of the region’s proved total. In reference to

the proved natural gas reserve, the figure is 3,462.9

billion cubic feet, of which 46.7 percent or 1,616.0 bil-

lion cubic feet correspond to associated gas, and the

remaining 53.3 percent is non-associated gas, that is,

1,846.9 billion cubic feet. Tables 6.8 and 6.9 illustrate

the composition of the 2P and 3P oil and natural gas

reserves. It should be noted that the non-associated

gas values reported include the reserves of gas-

condensate, dry gas, and wet gas reservoirs.


The proved oil reserve as of January 1, 2009 in the

Southwestern Offshore Region is 1,176.0 million bar-

rels, of which 563.4 million barrels or 47.9 percent is

in the Abkatún-Pol-Chuc Integral Business Unit, while

Table 6.8 Composition of 2P reserves by business unit of the Southwestern Offshore Region.



Total 337.2 1,375.3 449.0 2,519.8 3,619.0 Abkatún-Pol-Chuc 128.7 737.2 41.4 1,428.7 251.4 Holok-Temoa 0.0 0.0 0.0 0.0 915.5 Litoral de Tabasco 208.6 638.1 407.5 1,091.1 2,452.0

Table 6.9 Composition of 3P reserves by business unit of the Southwestern Offshore Region.



Total 739.9 1,793.1 684.4 3,232.9 6,338.9 Abkatún-Pol-Chuc 251.1 785.3 47.0 1,498.6 286.2 Holok-Temoa 0.0 0.0 0.0 0.0 2,430.3 Litoral de Tabasco 488.8 1,007.8 637.4 1,734.3 3,622.4

90


612.6 million barrels or 52.1 percent corresponds

to the Litoral de Tabasco Integral Business Unit. As

mentioned before, to date the Holok-Temoa Integral

Business Unit only manages natural gas fields.

In regional terms, the proved oil reserve reported a

net increase of 364.1 million barrels when compared

with January 1, 2008. Additionally, there was a net

rise of 323.6 million barrels of oil in the developed

proved reserve. Furthermore, the undeveloped

reserve increased by 40.5 million barrels of oil as

against the previous year. At an integral business unit

level, Abkatún-Pol-Chuc reported an increase of 185.3

million barrels, which corresponds to a developed

proved reserve volume of 199.6 million barrels, while

the undeveloped proved reserve decreased by 14.3

million barrels. The increase in the developed proved

reserve was essentially due to the revision of the

pressure-production behavior and the reclassification

of reserves in Ixtal, Chuc, Caan, Homol, and Manik

fields that jointly added 183.7 million barrels of oil. The

decrease reported in the undeveloped proved reserve

was largely due to the reclassification of undeveloped

reserves to developed as a result of drilling two wells

in the Ixtal field.

As of January 1, 2009, the Litoral de Tabasco Integral

Business Unit showed an increase of 178.9 million

barrels of crude oil in the proved reserve. This figure

is the result of increases in the developed proved

reserve of 124.0 million barrels and 54.8 million bar-

rels in the undeveloped proved reserve. The fields

that reported the most important positive variations

in the developed proved reserve are Bolontikú, Sinán,

May and Yaxché, with 74.8, 16.9, 14.4, and 13.2 million

barrels of oil, respectively, caused by development

in Bolontikú and May, revisions and development in

Sinán, and delineation activities in the latter field.

The Tsimin, Xanab and Tecoalli fields in the Litoral de

Tabasco Integral Business Unit reported increases in

the undeveloped proved oil reserve of 41.8, 9.7 and

6.1 million barrels through exploratory addition.

The proved natural gas reserves as of January 1,

2009 amounted to 3,462.9 billion cubic feet, of which

35.9 percent of the reserve, or 1,243.1 billion cubic

feet, are in the Abkatún-Pol-Chuc Integral Business

Unit, while the Litoral de Tabasco holds 1,911.2 bil-

lion cubic feet or 55.2 percent, and the remaining 8.9

percent, that is, a volume of 308.6 billion cubic feet,

is in Holok-Temoa.

The region’s proved natural gas reserve reported a net

increase of 1,049.8 billion cubic feet compared with

January 1, 2008. This variation consists of an increase

in developed proved reserves of 751.5 billion cubic

feet of natural gas and 298.3 billion cubic feet for the

undeveloped reserve. The Abkatún-Pol-Chuc Integral

Business Unit reported an increase in the proved

reserve of 359.4 billion cubic feet of natural gas. This

situation is explained by the positive variation of 402.6

billion cubic feet of gas in the developed proved re-

serve especially in the Ixtal, Caan, Chuc, Homol, Manik,

and Taratunich fields, with 184.5, 133.2, 52.8 20.3, 9.7,

and 9.3 billion cubic feet of gas, respectively, due to

the behavior and the reclassification of reserves.

The Litoral de Tabasco Integral Business Unit reported

an increase of 690.5 billion cubic feet of natural gas in

proved reserves, where the positive variation of 348.9

billion cubic feet is explained by the developed proved

reserves. There was also an increase of 341.6 billion

cubic feet of natural gas in the undeveloped proved

reserves. In particular, the increases reported in the

developed proved reserves category are basically

due to development activities in the May field that

meant 190.4 billion cubic feet of natural gas, Bolontikú

marked up an increase of 139.4 billion cubic feet, and

Sinán added 10.8 billion cubic feet of gas. As regards

the undeveloped proved reserve of natural gas, the

increase was essentially due to exploratory activities

in the Tsimin, Xanab, and Tecoalli fields that jointly

contributed a volume of 387.1 billion cubic feet of

natural gas. Additionally, there was a reduction of

44.1 billion cubic feet of gas in the May field caused

by development in the field.

91


The region’s probable oil reserve as of January 1,

2009 rose by 73.6 million barrels of crude oil when

compared with the previous year. In particular, the

Abkatún-Pol-Chuc Integral Business Unit reported a

decrease of 92.4 million barrels of oil, which combined

with the increase in the Litoral de Tabasco Integral

Business Unit of 166.0 million barrels of crude oil,

explain the above-mentioned positive variation. Basi-

cally, the exploratory activity permitted the addition of

reserves totaling more than 61 million barrels of oil in

the Xanab field, at the Jurassic level, and the Tsimin

and Tecoalli fields. There was also an increase of 35.8

million barrels of oil in the Sinán field because of de-

velopment and revision. The May and Bolontikú fields,

however, reported increases of 34.0 and 32.5 million

barrels of oil due to their development. Therefore,

the probable oil reserve amounted to 985.5 million

barrels as of January 1, 2009.

The probable natural gas reserve increased by 461.6

billion cubic feet of gas compared with the figure re-

ported as of January 1 last year. This variation includes

the decline reported in the Abkatún-Pol-Chuc Integral

Business Unit of 77.6 billion cubic feet of natural gas,

and the increase of 539.2 billion cubic feet of gas in the

Litoral de Tabasco. The most important reduction, that

is, more than 100 billion cubic feet of gas, was in Ixtal,

which comes under the Abkatún-Pol-Chuc Integral Busi-

ness Unit, as a result of reclassifying probable reserves

to proved caused by field development. In contrast,

the Homol field in the same business unit reported an

increase of 43.2 billion cubic feet of natural gas, due

to development. Furthermore, exploratory discoveries

in the Litoral de Tabasco Integral Business Unit added

210.2 billion cubic feet of gas. The development and

revision of the May, Bolontikú and Sinán fields led to

increases of 180.7, 65.6 and 80.2 billion cubic feet of

natural gas, which made up a positive variation in the

Litoral de Tabasco Integral Business Unit.

As of January 1, 2009, the region’s possible reserves

of oil and natural gas totaled 1,056.0 million barrels

and 3,433.0 billion cubic feet, respectively. The pos-

sible oil reserve in the Southwestern Offshore Region

showed a positive variation of 35.1 million barrels

compared with the figure estimated as of January 1,

2008. In this category, the Abkatún-Pol-Chuc Integral

Business Unit reported a decrease of 36.0 million

Table 6.10 Distribution of remaining gas reserves by business unit of the Southwestern Offshore Region as of January 1, 2009.


Proved Total 3,462.9 2,973.0 2,386.0 Abkatún-Pol-Chuc 1,243.1 1,003.0 782.7 Holok-Temoa 308.6 308.6 272.1 Litoral de Tabasco 1,911.2 1,661.4 1,331.2 Probable Total 2,675.9 2,388.4 1,983.2 Abkatún-Pol-Chuc 437.1 344.9 267.7 Holok-Temoa 606.9 606.9 535.2 Litoral de Tabasco 1,631.9 1,436.6 1,180.3 Possible Total 3,433.0 3,204.7 2,796.6 Abkatún-Pol-Chuc 104.6 77.0 59.8 Holok-Temoa 1,514.8 1,514.8 1,385.4 Litoral de Tabasco 1,813.6 1,612.8 1,351.4

92


barrels, which is mostly attributable to the delineation

of the Homol field that removed 35.5 million barrels

of oil. Nevertheless, there was a rise of 71.1 million

barrels of oil in this category in the Litoral de Tabasco

Integral Business Unit. The variation was basically

due to discoveries in the Tsimin, Tecoalli and Xanab

(Jurassic) fields that provided 48.1, 30.8 and 7.7 mil-

lion barrels of oil, respectively.

As regards the region’s possible natural gas reserve,

there was a positive variation of 165.4 billion cubic

feet when compared with the previous year. Specifi-

cally, there was a decline of 266.4 billion cubic feet of

gas in the Abkatún-Pol-Chuc Integral Business Unit,

largely caused by the delineation of Homol that led

to a reduction of 264.6 billion cubic feet of natural

gas. Nevertheless, the Litoral de Tabasco Integral

Business Unit reported a net increase of 432.0 billion

cubic feet in the possible natural gas reserve, with the

noteworthy exploratory success that added a volume

of 458.0 billion cubic feet of gas in the Tsimin, Tecoalli,

and Xanab fields of the Litoral de Tabasco Integral

Business Unit, amounting to 429.3, 21.6, and 7.2 bil-

lion cubic feet of natural gas, respectively. Table 6.10

shows the natural gas reserves by business unit in the

different categories, including gas to be delivered to

plant and dry gas.

Oil Equivalent

As of January 1, 2009, there was a proved reserve of

1,893.9 million barrels of oil equivalent in the South-

western Offshore Region. This volume represents

13.2 percent of the national total. Compared with

the previous year’s reserve, there is a net positive

variation of 524.1 million barrels in the reserve. Ac-

cording to Figure 6.13, the Abkatún-Pol-Chuc Integral

Business Unit holds 43.3 percent of the region’s total,

which means reserves of 819.3 million barrels of oil

equivalent, and a net increase of 245.0 million barrels

of oil equivalent when compared with the previous

year. These increases are basically due to revisions

in the Ixtal, Chuc, Caan, Homol, and Manik fields of

98.6, 57.4, 43.3, 18.5, and 14.9 million barrels of oil

equivalent, respectively.

The Litoral de Tabasco Integral Business Unit holds

53.0 percent of the region’s total proved reserves, that

is, 1,004.3 million barrels of oil equivalent, while the

remaining 3.7 percent is in the Holok-Temoa Integral

Business Unit. In the first business unit, the increases

totaled 279.0 million barrels of oil equivalent, which are

primarily explained by additions in the Tsimin, Xanab

(Jurassic), Yaxché (Tertiary), and Tecoalli fields that

contributed 117.7, 11.6, 11.4, and 7.1 million barrels

of oil equivalent, respectively. Additionally, there were

increases of 85.5 million barrels of oil equivalent in

Bolontikú and Sinán because of field development.

MMboe

Holok-Temoa

TotalAbkatún-Pol-Chuc

Litoral deTabasco

1,536.9130.1

973.5

433.2

Figure 6.14 Probable reserves as of January 1, 2009, distributed by business unit in the Southwestern Off-shore Region.

MMboe

Abkatún-Pol-Chuc

Holok-Temoa

Litoral deTabasco

Total

70.4

1,004.3

1,893.9819.3

Figure 6.13 Proved reserves as of January 1, 2009, dis-tributed by business unit in the Southwestern Offshore Region.

93


The region’s probable reserve amounted to 1,536.9

million barrels of oil equivalent as of January 1, 2009.

This volume represents 10.6 percent of the country’s

total reserves in this category. Figure 6.14 shows the

distribution of these reserves at a business unit level.

Compared with the figure for January 1, 2008, the

region’s current volume shows an increase of 132.2

million barrels of oil equivalent. In particular, the

fields of the Abkatún-Pol-Chuc Integral Business Unit

reported decreases totaling 116.2 million barrels of oil

equivalent, which was mainly caused by the reclas-

sification of reserves in Ixtal of 104.2 million barrels

of oil equivalent.

The positive variation of 248.9 million barrels of oil

equivalent in the Litoral de Tabasco Integral Business

Unit is primarily explained by the discoveries made

in the Tsimin, Xanab (Jurassic), Yaxché (Tertiary), and

Tecoalli fields that contributed 54.7, 38.8, 16.7, and

10.9 million barrels of oil equivalent, which means a

total of 121.1 million barrels. There were increases

by development in the May and Bolontikú fields of

50.7 and 44.0 million barrels. The increase in Sinán

as a result of development and revision amounted

to 48.6 million barrels of oil equivalent. It should also

be mentioned that there were reductions in the prob-

able oil equivalent reserve; nevertheless, they were

not significant to counteract the above-mentioned

successful results.

The region’s possible oil equivalent reserve as of

January 1, 2009 amounted to 1,758.5 million barrels,

as it is shown in Figure 6.15. This volume means

11.9 percent of the national total. Thus, there was an

increase of 33.4 million barrels when compared with

the previous year. At an integral business unit level,

Abkatún-Pol-Chuc showed a decrease of 95.2 million

barrels, most which was due to the delineation of the

Homol field, where the volume fell by 92.8 million bar-

rels of oil equivalent. The Litoral de Tabasco Integral

Business Unit reported a rise of 129.6 million barrels

of oil equivalent. The exploratory activity culminated

in the discovery of the Tsimin, Tecoalli, and Xanab (Ju-

rassic) fields, with 135.3, 36.0 and 9.1 million barrels.

There were also development and revision decreases

Figure 6.15 Possible reserves as of January 1, 2009, distributed by business unit in the Southwestern Off-shore Region.

MMboe

Holok-Temoa

TotalAbkatún-Pol-Chuc

Litoral deTabasco

1,758.5314.5

1,247.8

196.3

407.6 422.3509.7 Plant Liquids

Condensate

Dry GasEquivalent

Crude Oil

175.4 147.384.5

1,163.0 1,262.5

1,377.8

2,900.9 2,927.83,217.4

387.5 104.5197.7 -260.2

360.2185.2

724.9

4,043.5

4,647.0 4,759.9

5,189.4

Developments2006 2007 2008 2009

MMboe


2,773.1

Figure 6.16 Elements of change in the total reserve of the Southwestern Offshore Region.

94


in Sinán totaling 60.9 million barrels of oil equivalent,

nevertheless, they did not affect the favorable addition

results reported above.

Figure 6.16 shows the balance of the region’s 3P oil

equivalent reserves as of January 1, 2009, as com-

pared with 2006 to 2008.


The proved reserve-production ratio of the South-

western Offshore Region is 7.3 years considering a

constant production flow of 260.2 million barrels of

oil equivalent. The proved plus probable ratio is 13.2

years, while the ratio for the 3P reserve is 19.9 years.

In particular, the Abkatún-Pol-Chuc Integral Business

Unit showed the lowest value in this ratio, 5.3 years

for the proved reserve, while the Litoral de Tabasco

Integral Business Unit reported 9.6 years. The Holok-

Temoa Integral Business Unit is expected to add pro-

duction in 2012 with the Lakach integral project.

When the 2P oil equivalent reserves are considered,

the ratios are 8.1 and 18.9 years for Abkatún-Pol-Chuc

and Litoral de Tabasco integral business units, respec-

tively. When using the 3P or total reserves, the figure

is 9.3 years for the Abkatún-Pol-Chuc Integral Business

Unit and 30.8 years for the Litoral de Tabasco.


Hydrocarbon reserves in terms of fluid type are

shown in Table 6.11 as of January 1 in 2007 to 2009,

for the respective associated categories. The remain-

ing proved reserve at the closing of 2008 consisted

of 1,893.9 million barrels of oil equivalent, that is,

62.1 percent crude oil, 2.0 percent condensate, 11.7

percent plant liquids, and 24.2 percent is dry gas

equivalent to liquid.

The probable reserve volume of 1,536.9 million barrels

of oil equivalent is made up as follows: 64.1 percent

is crude oil, 1.5 percent is condensate, 9.5 percent is

plant liquids, and 24.8 percent is dry gas equivalent

to liquid.

The possible reserve amounting to 1,758.5 million

barrels of oil equivalent consists of 60.0 percent crude

oil, 1.3 percent condensate, 8.1 percent plant liquids,

and 30.6 percent dry gas equivalent to liquid.

Table 6.11 Historical evolution of reserves by fluid type in the Southwestern Offshore Region.


2007 Total 2,900.9 175.4 407.6 1,163.0 4,647.0 Proved 1,038.0 68.1 161.1 360.0 1,627.2 Probable 744.2 36.8 81.0 254.0 1,116.0 Possible 1,118.8 70.5 165.6 549.0 1,903.8 2008 Total 2,927.8 147.3 422.3 1,262.5 4,759.9 Proved 994.9 61.2 176.7 397.3 1,630.1 Probable 911.9 40.9 115.3 336.6 1,404.7 Possible 1,020.9 45.2 130.4 528.6 1,725.1

2009 Total 3,217.4 84.5 509.7 1,377.8 5,189.4 Proved 1,176.0 38.0 221.2 458.8 1,893.9 Probable 985.5 23.7 146.3 381.3 1,536.9 Possible 1,056.0 22.8 142.1 537.7 1,758.5

95


6.3 Northern Region

The region covers an area of approximately 1.8 million

square kilometers that consists of both onshore and

offshore portions. It is in the north of Mexico, border-

ing on the United States of America to the north, Río

Tesechoacán to the south, the 500 meter isobath of

the Gulf of Mexico to the east and the Pacific Ocean

to the west, Figure 6.17. As can be seen in Figure

6.18, the region is administratively divided into four

integral business units, the recently created Aceite

Terciario del Golfo, Burgos, Poza Rica-Altamira, and

Veracruz, whose activities are focused on develop-

ing and optimizing the exploitation of existing fields,

while the Regional Exploration Business Unit handles

the activities aimed at adding reserves and assessing

the potential.

As of January 1, 2009, the region was still the leading

producer of natural gas and it was also where most of

the field development activity was being carried out.

Once again, the Northern Region is the most important

in terms of Mexico’s probable and possible oil and

natural gas reserves.

In 2008, the region’s annual oil production was 31.9

million barrels, while the natural gas output amounted

to 931.1 billion cubic feet. These figures represent 3.1

and 36.8 percent of the national oil and gas produc-

tion, respectively.

In terms of national natural gas production in 2008,

the Northern Region was ranked first with an average

daily output of 2,543.9 million cubic feet. This is based

on drilling activities, especially in the Burgos Integral

Business Unit, where 201 wells were drilled.

Moreover, the exploratory activities in 2008 included

discoveries that led to the addition of non-associated

gas reserves in the Burgos and Veracruz integral

business units. In the case of the former, well Cali-1

stands out with the addition of dry gas reserves, while

Sonora

Coahuila

DurangoSinaloa

Nayarit

Nuevo León

Zacatecas


Guanajuato

Baja California Sur

Chihuahua

Jalisco

MichoacánColima

Querétaro

Puebla

D.F.México

TlaxcalaMorelos

Guerrero

Yucatán

Hidalgo

Tabasco

Chiapas

Guatemala

Belize

Quintana Roo

Oaxaca

Campeche


El Salvador

Honduras

Northern Region


Gulf of MexicoTamaulipas

VeracruzPacific Ocean

N

S

W E

100 200 300 400 500 Km0

Figure 6.17 The Northern Region consists of a continental and an offshore section.

96


in the Veracruz Integral Business Unit, the drilling of

well Cauchy-1 paved the way to the largest dry gas

discovery in 2008, thus adding the greatest volume

of dry gas reserves nationwide.

6.3.1 Evolution of Original Volumes in

Place

Table 6.12 shows the evolution of original

volumes of crude oil and natural gas in the

Northern Region over the last three years.

As of January 1, 2009, the volume of proved

oil was therefore 41,592.2 million barrels,

while natural gas totaled 66,663.6 billion cu-

bic feet. The above volumes represent 27.6

and 36.8 percent of the national total for oil

and natural gas. Regionally, 66.3 percent of

the proved original oil volume is in the fields

of the Poza Rica-Altamira Integral Business

Unit, while 31.5 percent corresponds to the

Aceite Terciario del Golfo Integral Business

Unit, and the remaining 2.2 percent is in the Burgos

and Veracruz integral business units. 60.1 percent

of the proved original natural gas volume is in the

fields of the Poza Rica-Altamira Integral Business Unit,

25.0 percent corresponds to the fields in the Burgos

100 200 300 400 5000 Km

Sonora

Coahuila

DurangoSinaloa

Nayarit

Nuevo León

Zacatecas

San Luis Potosí

Aguascalientes

Guanajuato

Baja California Sur

Chihuahua

Jalisco

MichoacánColima

Querétaro

PueblaD.F.

MéxicoTlaxcala

Morelos

Guerrero

Yucatán

Hidalgo

Tabasco

Chiapas

Guatemala

Belize

Quintana Roo

Oaxaca

Campeche


El Salvador

Honduras

BurgosIntegral Business Unit

Aceite Terciario del GolfoIntegral Business Unit

Veracruz Integral Business Unit


Tamaulipas

Veracruz

Gulf of Mexico

Pacific Ocean

N

S

W E

Altamira-Poza RicaIntegral Business Unit

Figure 6.18 Geographic location of the integral business units that constitute the Northern Region.

Table 6.12 Historical evolution over the last three years of the original volumes in the Northern Region.





97


Integral Business Unit, 8.2 percent is in the Veracruz

Integral Business Unit and 6.7 percent is in the Aceite

Terciario del Golfo Integral Business Unit.

The probable original oil and gas volumes amount

to 72,895.5 million barrels and 32,576.6 billion cubic

feet, which are equal to 86.4 and 75.4 percent of the

national totals, respectively. In regional terms, the

Aceite Terciario del Golfo Integral Business Unit holds

almost the entire probable volume of oil and 89.8 per-

cent of the probable original volume of natural gas, the

Burgos Integral Business Unit, however, accounts for

7.1 percent. The remaining 3.1 percent is in the Poza

Rica-Altamira and Veracruz integral business units.

As regards the possible original volumes of oil and

natural gas in the Northern Region as of January

1, 2009, the values are 51,752.8 million barrels and

24,660.4 billion cubic feet. The above volumes ac-

count for 81.7 and 73.3 percent of the national total,

respectively. Regionally, the Aceite Terciario del Golfo

Integral Business Unit has almost all the possible

crude oil volume, that is, 98.5 percent. This business

unit has 83.2 percent of the natural gas volume and the

Burgos Integral Business Unit possesses 11.8 percent.

The Veracruz and Poza Rica-Altamira integral business

units account for the remaining 5.0 percent.

The region’s proved original volume of associated

gas as of January 1, 2009, was 45,306.1 billion cubic

feet, while the volume for non-associated gas totaled

21,357.5 billion cubic feet. Specifically, in the case of

the former, 44,322.6 billion cubic feet are connected

with oil reservoirs, and 983.5 billion cubic feet cor-

respond to free associated gas reservoirs. 12,441.1

billion cubic feet of the non-associated gas volume

are in wet gas reservoirs, 8,596.9 billion cubic feet are

in dry gas accumulations, and 319.6 billion cubic feet

are gas-condensate reservoirs.

In reference to the probable original volume of natural

gas, 29,413.7 billion cubic feet are associated gas and

3,162.9 billion cubic feet are non-associated gas. Spe-

cifically, in the case of associated gas, 29,362.7 billion

cubic feet are in oil reservoirs, and 51.0 billion cubic

feet correspond to free associated gas reservoirs. In

terms of the volume of non-associated gas, 2,045.0

billion cubic feet are in wet gas reservoirs, 1,077.0 bil-

lion cubic feet are in dry gas reservoirs, and 41.0 billion

cubic feet are in gas-condensate reservoirs.

Finally, the possible original volume of natural gas

reserves, as of January 1, 2009, consisted of 21,484.5

billion cubic feet of associated gas and 3,175.9 billion

cubic feet of non-associated gas. 99.8 percent of the

associated gas is located in oil reservoirs, while 61.2

percent of the non-associated gas is to be found in

wet gas reservoirs, 38.0 percent in dry gas reservoir,

and the remaining 0.9 percent is in gas-condensate

reservoirs.


As of January 1, 2009 the Northern Region reported

an increase in the proved original oil volume of 415.7

million barrels when compared with the previous year

due to the reclassification of reserves to proved in

the Poza Rica-Altamira and Aceite Terciario del Golfo

integral business units. Specifically, the Poza Rica field

in the former and the Coapechaca and Presidente

Alemán fields in the latter stand out among said re-

classification activities.

The region reported a decrease of 129.0 billion cubic

feet in terms of the proved original volume of natural

gas, when compared with the previous year. This

decline was mostly in the Papán and Perdiz fields of

the Veracruz Integral Business Unit and Arcos field of

the Burgos Integral Business Unit.

The probable original volumes of oil and natural gas

in the region revealed a decline of 3,681.3 million bar-

rels and 702.7 billion cubic feet when compared with

January 1, 2008. This mostly took place in the Aceite

Terciario del Golfo Integral Business Unit as a result

of reclassifying probable volumes to possible.

98


There was an increase in the possible original volumes

of oil and natural gas in the Northern Region as of

January 1, 2009 totaling 3,572.0 million barrels and

1,313.5 billion cubic feet. This increase is essentially

attributed to the Aceite Terciario del Golfo Integral

Business Unit due to the reclassification of probable

volumes to possible category.


The proved oil reserve of the Northern Region as of

January 1, 2009 was 828.7 million barrels, of which

407.8 million barrels correspond to the developed

proved reserve and 420.9 million barrels to the un-

developed proved reserve. Additionally, the probable

and possible oil reserves are 5,845.0 and 5,729.2

million barrels, respectively. The 2P and 3P reserves

therefore add up to 6,673.7 and 12,402.9 million bar-

rels. The proved natural gas reserve is 4,218.7 billion

cubic feet, of which 2,890.5 billion cubic feet corre-

spond to the developed proved reserve and 1,328.2

billion cubic feet are undeveloped proved reserve.

Furthermore, 1,282.0 billion cubic feet of the proved

natural gas reserve are associated gas and 2,936.7

billion cubic feet are non-associated gas. The probable

and possible natural gas reserves total 14,901.3 and

17,383.0 billion cubic feet, respectively. The 2P and 3P

reserves therefore amount to 19,120.0 and 36,503.1

billion cubic feet of natural gas, respectively.

Figures 6.19 and 6.20 show the historical evolution

over the last 3 years of the proved, probable and

possible oil and natural gas reserves, while the

composition of the 2P and 3P reserves by fluid type

and at a business unit level are shown in Tables 6.13

and 6.14.

As of January 1, 2009, 8.0 percent of Mexico’s proved

oil reserve was in the Northern Region. In regional

terms, 60.5 percent of said reserve was in the Aceite

Terciario del Golfo Integral Business Unit, followed

by the Poza Rica-Altamira Integral Business Unit with

38.0 percent, and the Veracruz Integral Business Unit

with 1.5 percent. The region’s proved natural gas re-

serve represents 23.9 percent of the national total, of

which 45.8 percent is in the Burgos Integral Business

Unit in the first place, followed by the Veracruz, Aceite

Terciario del Golfo and Poza Rica-Altamira integral

business units, with 20.7, 19.5 and 13.9 percent,

respectively.

The developed proved oil and natural gas reserves as

of January 1, 2009, account for 5.3 and 25.2 percent,

in terms of national totals. In a regional context, the

Aceite Terciario del Golfo and Poza Rica-Altamira in-

tegral business units have almost all the developed

proved oil reserve, that is, 97.5 percent, with the re-

Figure 6.19 Historical evolution of the remain-ing crude oil reserves in the Northern Region over the last three years.

Proved

Probable

Possible

MMbbl

2007 2008 2009

6,099.7 6,056.7 5,845.0

5,780.8 5,648.7 5,729.2

12,769.4 12,546.0 12,402.9

888.9 840.7 828.7

Bcf

Proved

Probable

Possible

2007 2008 20094,856.4 4,479.7 4,218.7

15,874.2 15,624.9 14,901.3

18,179.4 17,441.5 17,383.0

38,910.0 37,546.1 36,503.1

Figure 6.20 Historical evolution of the remain-ing natural gas reserves in the Northern Region over the last three years.

99


mainder in the Veracruz Integral Business Unit. The

greatest proportion of the developed proved natural

gas reserve is in the Burgos Integral Business Unit,

with 46.2 percent, followed in second place by the

Veracruz Integral Business Unit with 26.5 percent.

The Poza Rica-Altamira and Aceite Terciario del Golfo

integral business units provide 16.1 and 11.2 percent,

respectively.

The undeveloped proved oil and natural gas reserves

represent 15.2 and 21.4 percent of the national total,

respectively. Regionally speaking, the Aceite Terciario

del Golfo Integral Business Unit has 79.0 percent of

the undeveloped proved oil reserve, followed by the

Poza Rica-Altamira Integral Business Unit with 20.4

percent. As regards the natural gas reserve, 45.0

percent of the undeveloped proved reserve is in the

Burgos Integral Business Unit, trailed by the Aceite

Terciario del Golfo Integral Business Unit with 37.8

percent, and the Poza Rica-Altamira Integral Business

Unit with 9.2 percent.

As of January 1, 2009, the region’s probable oil and

natural gas reserves represented 56.3 and 74.1 percent

of the national total, respectively. In regional terms, 94.2

percent of the oil reserve is associated with the Aceite

Terciario del Golfo Integral Business Unit because this

business unit holds all the reserves of the Paleocanal

de Chicontepec. This business unit also represents 86.4

percent of the probable natural gas reserves, followed

by the Burgos Integral Business Unit with 7.6 percent,

then the Poza Rica-Altamira and Veracruz integral busi-

ness units with 4.7 and 1.3 percent, respectively.

As of January 1, 2009, the possible oil and natural

gas reserves in the Northern Region represented 56.4

and 76.9 percent of the national total, respectively.

As in the case of the probable category, in regional

terms the Aceite Terciario del Golfo Integral Business

Unit reports the highest possible oil and natural gas

reserves, with 96.8 and 87.0 percent, once again,

because this business unit holds all the reserves of

the Paleocanal de Chicontepec.

Table 6.13 Composition of 2P reserves by business unit of the Northern Region.



Total 2,575.1 3,283.7 814.9 14,435.0 4,685.1 Aceite Terciario del Golfo 2,321.3 2,874.4 812.5 13,693.8 0.0 Burgos 0.0 0.0 0.0 3.8 3,062.6 Poza Rica-Altamira 235.7 409.2 2.4 702.3 589.6 Veracruz 18.1 0.0 0.0 35.1 1,032.8

Table 6.14 Composition of 3P reserves by business unit of the Northern Region.



Total 4,177.0 6,740.3 1,485.5 29,883.7 6,619.4 Aceite Terciario del Golfo 3,880.1 6,192.7 1,481.2 28,822.7 0.0 Burgos 0.0 0.0 0.0 3.8 4,783.1 Poza Rica-Altamira 268.4 547.7 4.3 937.5 729.3 Veracruz 28.5 0.0 0.0 119.7 1,107.0

100


The addition of proved, probable and possible re-

serves, also known as 3P, of oil and natural gas in the

Northern Region were 12,402.9 million barrels and

36,503.1 billion cubic feet, respectively. Nationally,

the above figures mean 40.1 and 60.5 percent, re-

spectively. Furthermore, in regional terms the Aceite

Terciario del Golfo Integral Business Unit makes up

most of the 3P oil reserve with 93.2 percent, that is,

11,554.0 million barrels. As regards natural gas, once

again the above-mentioned business unit was ranked

first with 79.0 percent, followed by the Burgos Integral

Business Unit with 13.1 percent and then the Poza

Rica-Altamira and Veracruz integral business units

with 4.6 and 3.4 percent, respectively.


Based on the field development activities carried on

in 2008, which meant the completion of 485 wells, the

oil and natural gas reserves in the Northern Region,

reported variations in the different categories, as can

be seen below.

As of January 1, 2009, the proved oil reserve volume

showed a net decrease of 12.0 million barrels when

compared with the previous year that can largely be

attributed to the production extracted in 2008, that is,

31.9 million barrels of oil. If the effect of the production

extracted is not considered, there is an increase in the

remaining proved reserve of 19.9 million barrels. This

situation is mostly due to field development activities,

especially in Corralillo, Agua Fría, and Coapechaca of

the Aceite Terciario del Golfo Integral Business Unit,

Aguacate and Poza Rica of the Poza Rica-Altamira

Integral Business Unit, and Perdiz of the Veracruz

Integral Business Unit. It should be noted that the re-

activation of mature fields in the region has paid off;

the tangible examples of this are the Temapache field

and recently in the Aguacate field, which form part of

the Poza Rica-Altamira Integral Business Unit.

There was a net decrease of 261.0 billion cubic feet in

the proved natural gas reserve, which was essentially

due to the production of 931.1 billion cubic feet of gas

in 2008. However, if the production effect is removed,

the remaining reserves increase by 670.1 billion cubic

feet of natural gas. Specifically, 22.6 percent of this

increase can be attributed to exploratory additions

totaling 151.2 billion cubic feet of natural gas, where

the Cali-1 well in the Burgos Basin and Cauchy-1 in

the Veracruz Basin stand out with the discovery of

22.0 and 86.1 billion cubic feet of gas, respectively.

Furthermore, the fields being exploited that reported

increases in the undeveloped proved natural gas re-

serve are Culebra, Nejo, Velero, Fundador, Cuervito,

and Forastero, of the Burgos Integral Business Unit,

with 49.7, 36.1, 32.0, 31.9, 34.3, and 28.5 billion cubic

feet of gas, respectively. There were also increases

in the Coapechaca, Corralillo, and Agua Fría fields, of

the Aceite Terciario del Golfo Integral Business Unit,

with 18.1, 13.1, and 11.6 billion cubic feet of gas, re-

spectively. Additionally, there were increases in the

Playuela, Lizamba, and Papán fields, of the Veracruz

Integral Business Unit, with 16.4, 13.2, and 11.6 billion

cubic feet of gas, respectively.

The probable oil and natural gas reserves of the North-

ern Region, as of January 1, 2009, totaled 5,845.0

million barrels and 14,901.3 billion cubic feet, respec-

tively. A comparison of the above figures with those

available as of January 1 the previous year reveals a

net decline of 211.7 million barrels of oil and 723.6 bil-

lion cubic feet of natural gas, respectively. The above

decreases are essentially due to the reclassification

of probable reserves to possible, and because of the

revision of oil and natural gas reserves in the Paleo-

canal de Chicontepec fields of the Aceite Terciario del

Golfo Integral Business Unit.

The possible oil and natural gas reserve volumes as of

January 1, 2009 are 5,729.2 million barrels and 17,383.0

billion cubic feet, respectively. The above values show

that when compared with the previous year, there is

a positive variation of 80.5 million barrels in the case

of oil and a decrease of 58.5 billion cubic feet in the

case of natural gas. The rise in possible oil reserves is

101


mainly due to the reclassification of probable reserves

to possible in the fields of the Paleocanal de Chicon-

tepec. The decrease reported in possible natural gas

reserves was caused by the behavior of the reservoirs,

principally in the Tajín, Patlache, Mareógrafo, Dandi,

Casta and Kosni fields with 111.4, 36.2, 28.1, 23.1, 14.1

and 10.2 billion cubic feet of gas, respectively. These

decreases were partially offset however by exploratory

additions that totaled 244.3 billion cubic feet of gas.

Finally, Table 6.15 shows the distribution

of the remaining gas reserves, as of Janu-

ary 1, 2009, by business unit.

Oil Equivalent

The proved reserve of the Northern

Re gion, as of January 1, 2009 totaled

1,652.4 million barrels of oil equivalent,

which is 11.5 percent of the proved

national reserve. Figure 6.21 shows the

distribution of the reserve by integral

business unit. There was a net increase

of 144.5 million barrels of oil equivalent

in this category as against the remaining reserves of

the previous year, as a result of exploratory additions,

field development activities, and revisions of the

pressure-production behavior in reservoirs.

The probable reserve expressed in oil equivalent

showed a net decrease of 371.5 million barrels, which

is primarily due to the reclassification of probable re-

serves to possible in the Paleocanal de Chicontepec

412.4

MMboe

391.2180.5 1,652.4

Veracruz TotalBurgosPoza Rica-Altamira

Aceite Terciariodel Golfo

668.2

Figure 6.21 Proved reserves as of January 1, 2009, distributed by business unit in the Northern Region.

Table 6.15 Distribution of remaining gas reserves by business unit of the Northern Region as of January 1, 2009.


Proved Total 4,218.7 3,922.4 3,693.3 Aceite Terciario del Golfo 824.6 727.2 603.0 Burgos 1,933.4 1,878.1 1,825.6 Poza Rica-Altamira 587.7 451.7 403.6 Veracruz 873.0 865.4 861.1

Probable Total 14,901.3 13,302.2 11,310.0 Aceite Terciario del Golfo 12,869.1 11,403.8 9,482.4 Burgos 1,133.0 1,105.5 1,075.5 Poza Rica-Altamira 704.3 600.3 560.5 Veracruz 194.9 192.6 191.5

Possible Total 17,383.0 15,389.9 13,001.8 Aceite Terciario del Golfo 15,129.0 13,274.5 10,970.5 Burgos 1,720.4 1,668.9 1,626.2 Poza Rica-Altamira 374.8 293.7 261.6 Veracruz 158.8 152.9 143.5

102


fields. Consequently, the reserve as of January 1, 2009

amounted to 8,862.6 million barrels of oil equivalent,

which is 61.1 percent of the national total. Figure 6.22

shows the distribution of probable reserves for all of

the region’s integral business units.

The possible oil equivalent reserve as of January 1,

2009 totaled 9,209.9 million barrels, which is 62.5

percent of the total national possible reserve. Figure

6.23 shows the distribution of possible reserves at

an integral business unit level. The reserves this year

increased by 16.4 million barrels of oil equivalent

when compared with the previous year, which is

essentially attributable to the exploratory additions

made in 2008.

The total or 3P reserve as of January 1,

2009 was 19,724.8 million barrels of oil

equivalent, which is 45.3 percent of the

national total. Specifically, the highest re-

gional percentage, that is, 88.2 percent, is

in the fields belonging to the Aceite Tercia-

rio del Golfo Integral Business Unit. When

comparing the 3P oil equivalent reserve

in question with the figure reported last

year, there is a net decline of 210.6 million

barrels, which is mostly due to the 213.6

million barrels of oil equivalent produced

in production in 2008. Figure 6.24 shows

the above and gives the composition of

the 3P reserves in the Northern Region.


As of January 1, 2009, the ratio of the proved reserve-

production for oil equivalent was 7.7 years. The above

estimate is the coefficient arising from dividing the

1P reserve by the production in 2008 of 213.6 million

barrels of oil equivalent. The 2P reserve, that is, the

proved plus probable oil equivalent reserves, has a

reserve-production ratio of 49.2 years, and the ratio

for the 3P reserve, that is, proved plus probable plus

possible reserves of oil equivalent, the figure is 92.4

years. The differences between the figure estimated

for 1P reserves and the estimates for 2P and 3P re-

serves are clearly because of the fact that

the latter two have been affected by the

probable and possible reserve volumes in

the fields of the Paleocanal de Chiconte-

pec belonging to the Aceite Terciario del

Golfo Integral Business Unit, which are

also in fact the highest volumes in these

categories nationwide.

The reserve-production ratio for the

proved oil reserve is 26.0 years, while

the period for the 2P and 3P reserves

are 209.4 and 389.1 years, respectively.

It should be mentioned that the above

341.58,590.5235.6 42.2 9,209.9

Poza Rica-Altamira


Veracruz TotalBurgos

MMboe

Figure 6.23 Possible reserves as of January 1, 2009, distributed by business unit in the Northern Region.

455.98,134.0

230.3 42.5 8,862.6

Poza Rica-Altamira


Veracruz TotalBurgos

MMboe

Figure 6.22 Probable reserves as of January 1, 2009, distributed by business unit in the Northern Region.

103


results consider an annual production of 31.9 million

barrels of oil. In the case of natural gas, the reserve-

production ratio for the 1P, 2P and 3P reserve is 4.5,

20.5 and 39.2 years, respectively. These figures are

obtained by using an annual natural gas production

of 931.1 billion cubic feet of natural gas.


Table 6.16 shows the evolution over the last three

years of the oil equivalent reserves broken down

by fluid type for the Northern Region. Based on the

above, it can be seen that for 2009, 50.2 percent of

the proved reserve volume consists of crude oil, 43.0

percent is dry gas equivalent to liquid, 6.4 percent

is plant liquids, and 0.5 percent is condensate. The

figures for the probable oil equivalent reserves are

made up as follows: 66.0 percent is oil, 24.5 percent

is dry gas equivalent to liquid, 9.5 percent is plant

liquids and 0.1 percent corresponds to condensate.

Finally, the possible oil equivalent reserve is made up

as follows: 62.2 percent is oil, 27.1 percent is dry gas

equivalent to liquid, 10.6 percent is plant liquids and

0.1 percent corresponds to condensate.

1,711.4 1,970.5 1,918.2 Plant LiquidsCondensate

Dry GasEquivalent

Crude Oil

51.5 39.4 19.4 19.1

5,876.7 5,613.0 5,384.6

12,877.3 12,769.4 12,546.0 12,402.9

109.2 -347.8 28.0 -213.6

1,659.4

5,950.9

20,539.1 20,397.0 20,149.0 19,724.8

Developments2006 2007 2008 2009

MMboe


Figure 6.24 Elements of change in the total reserve of the Northern Region.

Table 6.16 Historical evolution of reserves by fluid type in the Northern Region.


2007 Total 12,769.4 39.4 1,711.4 5,876.7 20,397.0 Proved 888.9 18.2 106.4 832.9 1,846.4 Probable 6,099.7 9.5 751.9 2,360.5 9,221.6 Possible 5,780.8 11.7 853.1 2,683.3 9,328.9 2008 Total 12,546.0 19.4 1,970.5 5,613.0 20,149.0 Proved 840.7 8.2 102.4 770.2 1,721.5 Probable 6,056.7 5.0 883.0 2,289.5 9,234.1 Possible 5,648.7 6.3 985.1 2,553.3 9,193.4

2009 Total 12,402.9 19.1 1,918.2 5,384.6 19,724.8 Proved 828.7 8.0 105.5 710.1 1,652.4 Probable 5,845.0 4.6 838.4 2,174.6 8,862.6 Possible 5,729.2 6.5 974.3 2,499.9 9,209.9

104


6.4 Southern Region

The Southern Region covers an area of approximately

390,000 square kilometers and it is in the southern

part of Mexico. To the north it borders on the Gulf

of Mexico, to the northwest it adjoins the Northern

Region at parallel 18 and Río Tesechoacán. The east-

ern part is limited by the Caribbean Sea, Belize and

Guatemala and to the south by the Pacific Ocean.

The region encompasses 8 states in Mexico: Guer-

rero, Oaxaca, Veracruz, Tabasco, Campeche, Chiapas,

Yucatán, and Quintana Roo, as can be seen in Figure

6.25. It currently consists of a Regional Exploration

Business Unit and five integral business units: Bellota-

Jujo, Cinco Presidentes, Macuspana, Muspac, and

Samaria-Luna, Figure 6.26. In 2008 the region admin-

istered 156 fields with remaining reserves; two more

than in the previous year. The additional fields, Rabasa

and Teotleco, are the result of exploratory activity.

The Cinco Presidentes Integral Business Unit has the

highest number of fields, 43, which represents 27.6

percent of the regional total.

In 2008, the regional production of hydrocarbons was

167.9 million barrels of crude oil and 530.9 billion

cubic feet of natural gas, which means 16.4 and 21.0

percent of the total national oil and gas production,

respectively. In reference to the production in terms

of oil equivalent, last year the Southern Region pro-

vided 287.8 million barrels, that is, 19.8 percent of

the national total, which as in previous years, puts

the region in second place.

6.4.1. Evolution of Original Volumes in Place

The region’s proved original volume of oil as of Janu-

ary 1, 2009 is 36,926.0 million barrels, which is 24.5

Sonora

Coahuila

DurangoSinaloa

Nayarit

Nuevo León

Zacatecas


Guanajuato

Baja California Sur

Chihuahua

Jalisco

MichoacánColima

Querétaro

Puebla

D.F.México

TlaxcalaMorelos

Guerrero

Yucatán

Hidalgo

Tabasco

Chiapas

Guatemala

Belize

Quintana Roo

Oaxaca

Campeche


El Salvador

Honduras

Pacific Ocean

Southern Region


Tamaulipas

Veracruz

N

S

W E

Gulf of Mexico

100 200 300 400 500 Km0

Figure 6.25 Geographical coverage of the Southern Region. It includes the states of Guerrero, Oaxaca, Veracruz, Tabasco, Campeche, Chiapas, Yucatán and Quintana Roo.

105


percent of the national proved original volume. Table

6.17 shows the evolution of the original oil volume

over the last 3 years. The original volumes of oil in

the probable and possible categories are 2,508.4 and

1,272.4 million barrels, respectively, which account

for 3.0 and 2.0 percent of the country’s total. Region-

ally speaking, the Samaria-Luna Integral Business

Unit produces the highest percentage of the proved

original volume of oil, that is, 33.6 percent. In terms

of probable original volumes of oil, the Bellota-Jujo

Integral Business Unit provides the largest

proportion, with 37.5 percent of the region’s

total. The Samaria-Luna Integral Business

Unit provides 64.1 percent of the regional

total of possible original oil volume.

The Southern Region contributes 38.0 per-

cent of the country’s total proved original

volume of natural gas, which means a

volume of 68,675.6 billion cubic feet. The

original volumes of natural gas in the prob-

able and possible categories are 4,276.9 and

1,505.0 billion cubic feet, respectively, which

means 9.9 and 4.5 percent of the national

total in said categories. Regionally, the Mus-

pac Integral Business Unit holds the highest

proved original volume of natural gas, with

Km10 20 30 40 500

Villahermosa

Chiapas

Oaxaca

Palenque

Campeche

Ocosingo

Tabasco

Veracruz

Coatzacoalcos

Muspac

Cinco Presidentes

Bellota-Jujo

Macuspana

Samaria-Luna

N

S

W E

Frontera

Figure 6.26 Geographical location of the integral business units of the Southern Region.

Table 6.17 Historical evolution over the last three years of the original volumes in the Southern Region.


2007 Total 38,686.4 70,440.7 Proved 36,358.3 66,706.6 Probable 1,406.2 2,711.8 Possible 921.9 1,022.3



106


23,384.5 billion cubic feet, that is, 34.1 percent of the

total. With a total of 1,310.0 billion cubic feet, the Bel-

lota-Jujo Integral Business Unit is the most important

provider of the region’s probable original gas volume,

with 30.6 percent. Finally, the highest percentage of the

possible original volume of natural gas is concentrated

in the Samaria-Luna Integral Business Unit, with 33.0

percent of the total.


As of January 2009, the Southern Region reported

an increase of 1.4 percent in the total or 3P original

volume of oil in comparison with the previous year,

which means, 40,706.7 million barrels. This increase

was mostly the result of a rise in the probable category

thanks to the development of the Sunuapa field and

the discovery of the Teotleco field.

The total or 3P original natural gas volume was

74,457.5 billion cubic feet, which means an increase

of 3.0 percent when compared with the previous year

that was mostly in the probable category, primarily

because of the addition of the new Teotleco field.

The proved original volume of oil as of January 1, 2009

was 36,926.0 million barrels, that is, 0.2 percent higher

than the figure for the previous year. This positive

variation originated in the Muspac and Samaria-Luna

integral business units where the Sunuapa, Caparro-

so-Pijije-Escuintle and Sen fields raised volumes by

124.0, 91.0 and 59.1 million barrels of oil, respectively.

The respective geological models were updated in

the first two fields as a result of drilling development

wells. The increase in the Sen field was also due to

the result of drilling 4 wells in 2008, and the new 3D

Chopo seismic interpretation.

The proved original volume of natural gas as of Janu-

ary 1, 2009, was 68,675.6 billion cubic feet, which

means an increase of 2.3 percent when compared

with the previous year. This increase can largely be

attributed to the Tizón field with 286.8 billion cubic

feet of natural gas that occurred as a result of field

development. Furthermore, the Costero field also

reported a sizeable rise of 240.0 billion cubic feet of

gas caused by the new seismic reinterpretation and

field development activities.

The probable original volume of crude oil increased by

16.3 percent compared to the previous year to a total

of 2,508.4 million barrels as of January 1, 2009. The

most important increase, 168.6 million barrels, was

in the Sunuapa field and it was due to the updating of

the geological model of the East block, as a result of

drilling the Sunuapa-302 and 304 wells. Noteworthy

increases were also reported in the Muspac and Cinco

Presidentes integral business units that were essen-

tially the result of additions made by the discoveries of

the Teotleco and Rabasa fields, which provided 127.0

and 53.0 million barrels of oil, respectively.

The probable original natural gas volume was 4,276.9

billion cubic feet as of January 1, 2009, which means

an increase of 16.1 percent as against the previous

year. This rise was mostly due to exploratory additions

as a result of the discoveries in the Teotleco and Ra-

basa fields, estimated at 340.3 and 35.0 billion cubic

feet of gas, respectively.

The original volume of oil in the possible category

was 1,272.4 million barrels, that is, 12.6 percent

higher than the figure for the previous year. As in

the previous cases, this increase is essentially due to

the exploratory addition of the Rabasa and Teotleco

fields, which contributed 54.0 and 52.7 million barrels

of oil, respectively.

The possible original natural gas volume as of Janu-

ary 1, 2009 is 1,505.0 billion cubic feet, which means

a rise of 6.7 percent when compared with the year

2008. This positive variation was primarily because

of Sen and Paché fields, with the addition of 157.5

and 142.8 billion cubic feet of gas, respectively. Fur-

thermore, the discovery of the Teotleco field added

141.2 billion cubic feet of gas. The increase in the Sen

107


field is due to the updating of the 3D Chopo seismic

reinterpretation, and also to the result of the static

characterization study in the Paché field.


The Southern Region’s total or 3P reserves as of Janu-

ary 1, 2009 are 3,652.9 million barrels of oil and 9,406.5

billion cubic feet of natural gas, which accounts for

11.8 and 15.6 percent, respectively, of the national

total reserves. Figures 6.27 and 6.28 show the historic

evolution of oil and natural gas reserves over the last

three years in the region.

The region’s 2P or proved plus probable reserves, as

of January 1, 2009, totaled 3,181.1 million barrels of

oil and 8,504.3 billion cubic feet of natural gas, which

is 15.3 and 22.5 percent, respectively, of the country’s

total. Tables 6.18 and 6.19 show the distribution of the

2P and 3P reserves at a business unit level, classified

as heavy, light and superlight oil; the gas is given as

associated and non-associated gas.

The region’s proved oil reserve reported as of January

1, 2009, was 2,480.2 million barrels, that is, 23.8 per-

cent of the country’s total proved reserve. Regionally,

the oil reserve in this category is mostly in the Samaria-

Luna Integral Business Unit, with 49.2 percent, or in

other words 1,220.5 million barrels of oil. The region’s

proved natural gas reserve amounts to 2,650.0 billion

cubic feet, with is equal to 37.4 percent of the national

total, where the Samaria-Luna Integral Business Unit

is the most important, with a contribution of 40.1 per-

cent of the regional total, followed by the Bellota-Jujo

Integral Business Unit with 32.6 percent.

The developed proved oil and natural gas reserve as

of January 1, 2009 were 1,719.4 million barrels and

4,062.8 billion cubic feet, which account for 22.5 and

35.5 percent of the national total, respectively. The

undeveloped proved reserves, however, were 760.9

million barrels of crude oil and 2,539.3 billion cubic

feet of natural gas, that is, the equivalent of 27.5 and

41.0 percent of the national total.

The region’s proved oil reserves are made up as fol-

lows: 1,910.2 million barrels of light oil or 77.0 percent,

followed by superlight reserves and finally by heavy

oil reserves with 520.5 and 49.5 million barrels, re-

spectively, that are equal to 21.0 and 2.0 percent. The

most important light oil fields are Jujo-Tecominoacán,

Samaria, and Iride, with 1,401.2 million barrels of oil,

which is 73.4 percent of the regional total.

In reference to the Southern Region’s proved natural

gas reserve, this volume is made up of 5,222.8 billion

cubic feet of associated gas, which is 79.1 percent of

Figure 6.28 Historical evolution of the remain-ing natural gas reserves in the Southern Re-gion over the last three years.

Figure 6.27 Historical evolution of the remain-ing crude oil reserves in the Southern Region over the last three years.

Proved

Probable

Possible

MMbbl

2007 2008 2009

2,588.7 2,612.8 2,480.2

745.3 765.8700.8

393.9 422.4471.8

3,727.9 3,801.0 3,652.9

Bcf

Proved

Probable

Possible

2007 2008 2009

7,418.4 7,174.0 6,602.1

2,042.2 1,938.21,902.2

996.0 1,048.2902.2

10,456.6 10,160.49,406.5

108


the regional total, while the non-associated gas con-

stitutes the remaining 20.9 percent or 1,379.3 billion

cubic feet. The associated gas fields that provided the

most reserves are Jujo-Tecominoacán, Iride, Samaria,

Cunduacán, and Oxiacaque, which jointly provide

3,488.3 billion cubic feet of gas, while the most sig-

nificant non-associated gas contribution came from

the Chiapas-Copanó, Giraldas, Costero, Narváez and

Muspac fields, with 879.8 billion cubic feet of gas.

The region’s probable oil reserve amount is estimated

at 700.8 million barrels, which is 6.8 percent of the

national total, while the natural gas reserve is 1,902.2

billion cubic feet, that is, 9.5 percent of the national

total. The most important probable oil reserves are in

the Samaria-Luna and Bellota-Jujo integral business

units, particularly in the Samaria and Cunduacán fields

with 210.4 million barrels of oil, and Tajón and Tepeyil

with 50.5 million barrels.

The region’s possible reserves totaled 471.8 million

barrels of oil, that is, 4.6 percent of the national total,

while in the case of gas, the possible reserve was

902.2 billion cubic feet, or 4.0 percent of the country’s

reserves. 64.8 percent of the possible oil reserves, that

is 305.6 million barrels, are in the Magallanes-Tucán-

Pajonal, Iride, Carrizo, Sitio Grande, Sen, Samaria and

Sunuapa fields.


Compared with the previous year, the Southern

Region’s proved oil reserves as of January 1, 2009

increased by 1.3 percent to 2,480.2 million barrels.

This positive variation was mostly in the Sen, Cos-

tero, Sunuapa, Caparroso-Pijije-Escuintle, Guaricho

and Mora fields, which jointly reclassified 101.6 mil-

lion barrels of oil as proved reserve. The increase in

these fields was due to the updating of the respective

Table 6.18 Composition of 2P reserves by business unit of the Southern Region.



Total 194.8 2,137.2 849.0 6,282.0 2,222.3 Bellota-Jujo 27.4 791.0 254.0 2,322.5 122.6 Cinco Presidentes 17.5 249.0 16.5 369.5 20.3 Macuspana 0.0 15.4 66.7 7.7 1,096.0 Muspac 15.2 49.9 142.7 521.8 810.4 Samaria-Luna 134.7 1,031.9 369.1 3,060.5 173.0

Table 6.19 Composition of 3P reserves by business unit of the Southern Region.



Total 350.1 2,327.1 975.6 6,758.4 2,648.2 Bellota-Jujo 29.6 798.5 267.5 2,361.4 131.5 Cinco Presidentes 29.9 336.0 24.5 477.3 51.2 Macuspana 0.0 15.5 81.7 7.8 1,291.6 Muspac 15.7 144.2 183.3 728.8 946.6 Samaria-Luna 274.9 1,032.9 418.6 3,183.0 227.3

109


geological models as a result of drilling development

wells in 2008.

The Southern Region’s proved natural gas reserves,

compared with the previous year, declined by 41.0

billion cubic feet and reached a value of 6,602.1 bil-

lion cubic feet as of January 1, 2009. The decrease is

largely explained by the production of 530.9 billion

cubic feet of natural gas and the reduction in the Sa-

maria and Chiapas-Copanó fields of 172.8 billion cubic

feet of gas. As regards the increases in this category

of reserve, the Costero field reported a value of 160.6

billion cubic feet of natural gas that is attributable to

the new geological model based on the successful

completion of the Costero-12, 31, and 2, wells.

The region’s probable oil reserves as of January 1, 2009

totaled 700.8 million barrels, which means a decrease

of 64.9 million barrels compared with the reserve as of

January 1. 2008. This decline in reserves was mostly

due to the reductions reported in the Tajón, Paché, Iride,

Palangre and Yagual fields totaling 160.8 million barrels

of oil. In the Tajón field, the decrease was caused by

a revision of the pressure-production behavior in the

Tajón-101 well, and the adverse results obtained by

drilling the Tajón-105 and 121 wells. In the case of the

Paché, Palangre and Yagual fields, the reason is the

removal of blocks in these fields and in Iride, it was

caused by a revision of the field’s pressure-production

behavior. There some were increases, but they were not

able to compensate for the reductions. For example,

the discoveries in the Teotleco and Rabasa fields added

30.8 and 12.2 million barrels of oil, respectively.

The region’s probable natural gas reserve reported a

decline of 36.0 billion cubic feet compared with Janu-

ary 1, 2008. Consequently, as of January 1, 2009, the

reserve was 1,902.2 billion cubic feet of natural gas.

The reduction in reserves was basically due to the

revision of the Paché field.

Table 6.20 Distribution of remaining gas reserves by business unit of the Southern Region as of January 1, 2009.


Proved Total 6,602.1 6,242.2 4,782.2 Bellota-Jujo 2,155.4 1,942.4 1,461.8 Cinco Presidentes 271.6 219.6 180.7 Macuspana 609.3 596.5 520.7 Muspac 915.9 881.2 662.5 Samaria-Luna 2,650.0 2,602.5 1,956.4 Probable Total 1,902.2 1,805.7 1,400.9 Bellota-Jujo 289.7 257.1 193.5 Cinco Presidentes 118.2 100.9 83.0 Macuspana 494.4 489.1 398.6 Muspac 416.3 385.4 294.9 Samaria-Luna 583.5 573.3 431.0 Possible Total 902.2 837.2 649.0 Bellota-Jujo 47.8 42.3 33.5 Cinco Presidentes 138.7 90.5 74.5 Macuspana 195.7 193.9 150.9 Muspac 343.2 336.4 259.2 Samaria-Luna 176.8 174.1 130.9

110


The region’s possible oil reserves as of January 1,

2009 increased by 49.4 million barrels, when com-

pared with the figure reported as of January 1, 2008,

to the figure of 471.8 million barrels. This increase

mostly took place in Sen, Paché, Teotleco, Rabasa

and Sunuapa fields, with 16.9, 13.5, 12.7, 12.4 and

10.3 million barrels, respectively. The development

of the Sen field and the characterization study of the

Paché field led to an increase in this category of re-

serve, which is also the case of the discoveries in the

Teotleco and Rabasa fields as a result of exploratory

activity. The possible natural gas reserves, however,

declined by 146.0 billion cubic feet when compared

with the previous year, which meant a remaining re-

serve value of 902.2 billion cubic feet as of January 1,

2009. The most important negative variation was in

the Costero field, due to the revision of the geologi-

cal model based on drilling development wells. Table

6.20 shows the distribution of natural gas, gas to be

delivered to plant and dry gas reserves in the proved,

probable and possible categories.

Oil Equivalent

The volume of 3P reserve in terms of oil equivalent,

that is, proved plus probable plus possible reserves

as of January 1, 2009 totaled 5,862.5 million barrels,

which is 13.5 percent of the total national reserve.

When compared with the previous year, this value

means a reduction of 1.1 percent considering the

948.1 898.4 Plant LiquidsCondensate

Dry GasEquivalent

Crude Oil

116.6 91.0 95.8 89.2

1,479.4 1,420.9

84.7 -200.6 50.1 -287.8

1,038.7

1,610.0

6,641.46,246.3 6,216.1

5,862.5

Developments2006 2007 2008

MMboe


3,876.1 3,727.9 3,801.0 3,652.9

2009

806.8

1,313.6

Figure 6.29 Elements of change in the total reserve of the Southern Region.

MMboe

1,439.7

Bellota-Jujo

1,877.3

Samaria-Luna

316.1

Muspac

4,049.1

Total

169.0

Macuspana

247.0

CincoPresidentes

Figure 6.30 Proved reserves as of January 1, 2009, distributed by business unit in the Southern Region.

111


production obtained in 2008. The 3P reserve mostly

lies in the fields of the Samaria-Luna and Bellota-Jujo

integral business units, which hold 72.5 percent of the

total. Figure 6.29 shows the variation in 3P reserves

over 2008, compared with 2006 and 2007.

The Southern Region’s proved reserve, as of Janu-

ary 1, 2009 in terms of oil equivalent amounted to

4,049.1 million barrels, which is 28.3 percent of the

proved national reserve, Figure 6.30. When com-

pared with last year, the reserve decreased by 4.2

million barrels of oil equivalent; said negative varia-

tion was mostly the result of revising the pressure-

production behavior in the Jujo-Tecominoacán and

Samaria fields.

The region’s probable oil equivalent reserve, as of

January 1, 2009, amounted to 1,140.3 million barrels,

or 7.9 percent of the country’s probable reserves,

Figure 6.31. This means a decrease of 75.0 million

barrels of oil equivalent in this category, compared

to the volume of remaining reserves in the previous

year. The situation was mainly caused by unfavorable

well drilling activities in 2008 in the Tajón field.

As of January 1, 2009, the possible reserve amounted

to 673.0 million barrels of oil equivalent, which is 4.6

percent of the country’s possible reserves, Figure

6.32. Compared with the previous year, the region’s

possible reserve showed an increase of 13.3 million

barrels of oil equivalent. This positive variation was

Figure 6.31 Probable reserves as of January 1, 2009, distributed by business unit in the Southern Region.

208.4

117.8153.9

201.9

458.4

1,140.3

CincoPresidentes

Muspac Total

MMboe

Bellota-Jujo

MacuspanaSamaria-Luna

Figure 6.32 Possible reserves as of January 1, 2009, distributed by business unit in the Southern Region.

215.7

232.8

130.660.5

33.4 673.0

Macuspana Total

MMboe

CincoPresidentes

MuspacSamaria-Luna

Bellota-Jujo

112


mostly in the Sen, Paché, Teotleco and Rabasa fields,

which jointly added 82.0 million barrels. Neverthe-

less, this increase was counteracted by the Costero

and Tizón fields, whose reserves fell by 40.0 and 30.6

million barrels of oil equivalent, respectively.


The proved oil reserve-production ratio of the South-

ern Region is 14.8 years if an annual production of

167.9 million barrels of oil is used. If the ratio is calcu-

lated for the 2P reserve, the figure is 18.9 years, and

21.8 years in the case of 3P reserves. The Samaria-

Luna Integral Business Unit has the highest proved

oil reserve-production ratio in the region, with 18.1

years, followed by the Bellota-Jujo Integral Business

Unit with a ratio of 14.6 years.

The proved natural gas reserve-production ratio is

12.4 years when using an annual production of 530.9

billion cubic feet, while values of 16.0 and 17.7 years,

respectively, are obtained for the 2P and 3P reserve

categories. The Bellota-Jujo Integral Business Unit

has the highest proved reserve-production ratio in

the region, with 23.5 years.

The region’s proved reserve-production ratio, in terms

of oil equivalent, is 14.1 years, considering a produc-

tion of 287.8 million barrels of oil equivalent in 2008.

The ratio for the 2P reserve is 18.0 years and 20.4

years for the 3P reserve. The Bellota-Jujo and Samaria-

Luna integral business units show the highest proved

reserve-production ratio in the region, with 16.9 and

16.2 years, respectively.


The Southern Region’s proved reserve is made up of

61.3 percent crude oil, 1.9 percent condensate, 14.2

percent plant liquids, and 22.7 percent dry gas equiva-

lent to liquid. According to the above, the existence of

a large number of non-associated gas, oil and associ-

ated gas reservoirs with high gas-oil ratios is evident.

Furthermore, it can be seen that the gas produced by

these reservoirs has a high amount of liquids that are

recovered in the processing complexes.

The probable reserve totals 1,140.3 million barrels of

oil equivalent, of which 61.5 percent is crude oil, 1.0

percent is condensate, 13.9 percent is plant liquids,

and 23.6 percent is dry gas equivalent to liquid.

Table 6.21 Historical evolution of reserves by fluid type in the Southern Region.


2007 Total 3,727.9 91.0 948.1 1,479.4 6,246.3 Proved 2,588.7 78.9 671.6 1,049.2 4,388.4 Probable 745.3 9.5 184.6 290.3 1,229.7 Possible 393.9 2.6 91.9 139.9 628.2 2008 Total 3,801.0 95.8 898.4 1,420.9 6,216.1 Proved 2,612.8 82.8 645.9 999.5 4,341.1 Probable 765.8 11.0 162.3 276.2 1,215.3 Possible 422.4 2.0 90.2 145.1 659.8 2009 Total 3,652.9 89.2 806.8 1,313.6 5,862.5 Proved 2,480.2 76.3 573.1 919.5 4,049.1 Probable 700.8 11.1 159.0 269.4 1,140.3 Possible 471.8 1.8 74.7 124.8 673.0

113


Finally, the possible reserve amounts to 673.0 million

barrels of oil equivalent, which is made up as follows:

70.1 percent is crude oil, 0.3 percent is condensate,

11.1 percent is plant liquids, and 18.5 percent is dry

gas equivalent to liquid. Table 6.21 shows the distribu-

tion of the Southern Region’s hydrocarbon reserves

by fluid type over the last three years in the proved,

probable and possible categories.

114


Documents

Distribution of Hydrocarbon Reserves