American Oil and Gas Reporter - May 2015 - 63

Investment Attractiveness
In general, the investment attractiveness of the areas offered
in round one depends on a combination of the geological nature
of the type of resource, the cost of exploration and development,
and the applicable fiscal terms. In the immediate term, low oil
prices weigh in significantly. In this context, it is relevant to examine how round one is designed because it provides some margin of maneuver for the state. The series of five stages allows the
government to receive feedback from participants and adjust contract terms before final bidding for each area takes place. Each
phase can choose between four types of contracts, but it seems
that in practice, the options come down to whether to offer areas under PSAs or royalty-and-tax licenses, which are two of the
most common schemes in the industry.
Accordingly, the government could incentivize the extra-heavy
crude oil, deep water or unconventional areas by using a royalty-and-tax license scheme. In addition, for the first shallow-water phase of round one, the government has placed a restriction
on the partnerships that can be formed so larger companies (those
with daily production in excess of 1.6 million barrels of oil equivalent) cannot form a consortium. This was done partly with the
intent of increasing competition among big international oil companies, but it has been indicated that such restrictions will not exist for other areas, such as deep water.
However, the government will set a minimum bid value in deep
water, which basically indicates the minimum payment to the state,
and this will be set when the final bidding terms for each phase
are published. This could be a discouraging signal if participants
assess this floor to be too high.

Production Sharing Contract
The shallow-water blocks and fields are located near infrastructure and are expected to have a production cost below $20 a boe
with potential production of light crude oil. A comparison of the
regime with applicable shallow-water areas in the U.S. Gulf of
Mexico and other Latin American nations suggests that bids offering the government an initial 20 percent share of profit oil may
be competitive (Figure 3).
While the regime appears relatively responsive to low oil prices
and some assets could remain profitable at $50 oil up to a bid of

FIGURE 3
Regional Comparison
Of Mexico's Production Sharing Agreement
4.0

20.0
18.0

3.5

16.0
3.0

$U.S. NPV10/boe

14.0
2.5

12.0

2.0

10.0

IRR %

It is important to note that in addition to the extraction (production) and exploration areas, the round is synchronizing the first
farm-out areas in which Pemex is looking to establish partnerships
in producing or exploration assets. These would include assets in
all of the different areas considered for round one (i.e., shallow
water, onshore, extra-heavy, deep water, and unconventional).
The importance of how these farm-outs actually are concluded in the initial round lies in signaling how attractive future farmouts will be to interested operators. Pemex's new fiscal regime
aims to lower the government take of net profits from 78 percent
to 65 percent over the next five years. However, the government
take is not yet radically different from previous years, and in this
context, Pemex has an interest in participating in the relatively
more attractive terms of the new contract schemes.
As of mid-April, CNH still needed to do the call for bids on
onshore assets (expected by late April or early May), deep water and extra-heavy crude oil assets (possibly June), and unconventional assets (no indication of a date so far). For the shallowwater assets, CNH has scheduled the release of final contract terms
for exploration blocks by May 29 and the bidding deadline by
July 15, and for shallow-water discovered assets the release of
final contract terms by Aug. 14 and the bidding deadline by Sept.
30. It is likely that the bidding deadlines for the other areas will
extend until late 2015 or even into early 2016.

8.0

1.5

6.0
1.0
4.0
0.5
2.0
0.0

Brazil
Concession Agreement Shallow Water

U.S. OCS
Royalty and Tax - Shallow
Water Gulf of Mexico

Mexico PSA
20% Profit Oil Bid

NPV10/boe (U.S.$)

Argentina
Concession Agreement Onshore

Colombia
Royalty and Tax - Onshore

0.0

IRR (%)

30 percent, the profitability of a PSA contract might be challenged
at $40 oil. The final value of the biddable parameter determining the state's initial share of profit oil will be a significant determinant of the attractiveness of Mexico's production sharing
contract regime.
The extra-heavy oil fields in shallow water also set for bidding
could appear less attractive than other discovered shallow-water
fields because of the significant price discounts associated with
their low-quality crude. To date, CNH has indicated that the contract type for extra-heavy oil projects will be the same as the one
applicable to the deepwater exploration blocks (royalty-and-tax).
For deepwater areas, it is expected that the government will offer royalty-and-tax licenses, reflecting the high costs and risks associated with deepwater exploration and development.
The onshore assets in round one include both extraction and
exploration areas. Some of these are conventional producing fields
located in the southeast of the country and some are unconventional areas in Central to Northwest Mexico, not far from the Gulf
Coast. However, the onshore area with the largest proved, probable and possible reserves is located in the Chicontepec Basin.
With approximately 7 billion boe in estimated resources,
Chicontepec is thought to require continuous drilling to increase
and sustain production, similar to unconventional resource play
development methods.
For the unconventional exploration block, there is an additional negative aspect in that some of these areas lack the infrastructure of other onshore areas (mainly pipelines), making them unlikely to be profitable at current price levels. In this context, there
is not much that the government could do to improve attractiveness, and although data room access could be made less costly
so that smaller independent companies have an incentive to participate, the unconventional assets are perceived as the most disadvantageous phase of round one.
Shallow-Water Phase
With the drop in international crude oil prices, some of the areas considered in round one do not appear as attractive as they
did at the end of 2013. Moreover, with the first PSA terms published for shallow-water blocks and fields, it seems that operators consider the fiscal terms too harsh because the built-in adjustment mechanism favors the state whenever there is an upside
in revenues.
Furthermore, the government is expected to set a minimum

MAY 2015 63

American Oil and Gas Reporter - May 2015

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