Brief

Understanding Offshore UnitizationBrazil and the U.S. ComparedA Primer for Oil and Gas Professionals

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Understanding Offshore Unitization—Brazil and the U.S. Compared

L. Poe Leggette

Gabrielle Mattioda

Baker & Hostetler LLP

Denver, CO, USA

The continental shelves of the United States and Brazil contain world-class oil and gas

resources. Since the United States first proclaimed rights over its continental shelf in 1945, holders

of oil and gas lease rights have produced tens of billions of barrels of oil and condensate, and tens

of trillions of cubic feet of natural gas. Based on the most recent data available, that part of the U.S.

continental shelf under federal government control—called the Outer Continental Shelf (“OCS”)—

is producing approximately 1.45 million barrels of oil per day and 3.65 billion cubic feet of natural

gas per day.

Source: U.S. Bureau of Safety and Environmental Enforcement

Brazilian offshore production has increased steadily as well. Between June 2011 and June

2015, Brazilian production from its renowned “pre-salt” jumped from 154,000 to 926,000 barrels of

oil equivalent per day. Total Brazilian offshore oil production in 2014 averaged 2.09 million barrels

per day.

2

Source: Produção de Petróleo e Gás Natural por Estado (2000-2014) http://www.bdep.gov.br/?id=574

Both Brazil and the United States grant to private companies rights to explore for and

produce offshore oil and gas long before the locations of oil and gas reservoirs are established. But

it is rare that the boundaries of reservoirs neatly line up within the boundaries of the leases or

concession areas granted by the governments.1

For that reason, both Brazil and the United States have recognized that after exploration is

under way, it can be more efficient to erase those lease or concession lines and allow development

of potential oil and gas reserves in a combined area. This benefit is achieved through modifying the

agreements to treat the areas as if they were part of an individual legal unit. This concept is called

“unitization” in the United States and “individualização”—literally, “individualization”—in Brazil.

For convenience, we refer to the practice in both countries as unitization. This paper is an

introduction to the basic ideas that govern unitization on the Brazilian continental shelf and the

American OCS.2

1 As the U.S. Court of Appeals for the Tenth Circuit noted recently, “The problem, of course, is that mineral deposits

don’t always follow plat [property] lines.” Entek GRB, LLC v. Stull Ranches, LLC, 763 F.3d 1252, 1254 (10th

Cir.

2014). 2 While this paper appears to be the first to compare the Brazilian and American approaches to offshore unitization, it is

hardly the first to take up the developing law of unitization in Brazil. It is our privilege to know all four American

authors of the leading papers on Brazilian unitization. Professor Owen Anderson and practitioner Andrew Derman have

published insightful papers on Brazilian practice. Owen L. Anderson,” Unitization,”

http://www.epge.fgv.br/conferencias/microeconomics2011/anexos.php?path=files/15_12_11/OwenAnderson&file=m_

Unitization_Agreements.pptx. DERMAN, A. B., & MELSHEIMER, A., “Unitization agreements: a primer on the legal

issues for unitization of the Brazilian pre-salt,” Rio Oil & Gas Conference 2010, Rio de Janeiro. Anais. Rio de Janeiro:

Instituto Brasileiro de Petróleo, Gás e Biocombustíveis, 2010. Brazil’s law on unitization was also considered, along

with that of 11 other non-U.S. jurisdictions, in a jointly authored article by Professor Jacqueline Weaver and

practitioner David Asmus. J. Weaver & D. Asmus, “Unitizing Oil and Gas Fields Around the World: A Comparative

Analysis of National Laws and Private Contracts,” 28 Hous. J. Int’l L. 3 (2006). Brazil has made substantial changes in

its laws and regulations, however, since that article was published. The authors also thank Monica Rebelo Rodriguez,

senior consultant at Petrobrás, for sharing her knowledge of oil and gas in Brazil.

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1. In what form does the government grant rights to private companies to explore for and

produce offshore oil and gas?

United States

The U.S. government issues rights in the form of an oil and gas lease. The lease is both a

contract and a grant of a right in property. It is a contract because it is an agreement between the

government and one or more private parties. As a contract, it is interpreted under the usual rules of

contract interpretation, just as a contract entirely between private parties would be. Mobil Oil

Exploration & Producing Southeast, Inc. v. United States, 530 U.S. 604, 607-08 (2000). It is a grant

of private property because the U.S. Congress wished to use a kind of agreement with which the

American oil and gas industry was already familiar: the private oil and gas lease. Union Oil Co. of

California v. Morton, 512 F.2d 743, 747 (9th

Cir. 1975). As a kind of property, a lease is protected

by the Takings Clause of the Fifth Amendment to the U.S. Constitution. If the U.S. government

thoroughly interferes with a lessee’s rights granted under the lease, that interference will be

considered a “taking” of the lease, and the government will have to pay the lessee the fair value of

the lease.3

The U.S. government, acting through its Department of the Interior (DOI), has divided the

American continental shelf into “planning areas.” Every five years, DOI issues a schedule of “lease

sales” to be offered in those planning areas it wishes to open for oil and gas activity. Within the

U.S. Gulf of Mexico, for example, three planning areas have been established. For nearly four

decades it has been the practice of DOI to hold annual lease sales in two of those three areas: the

Western Gulf of Mexico and the Central Gulf of Mexico planning areas.

Before each lease sale, DOI publishes a notice of proposed sale, making available to

potential bidders the lease agreement and any additional lease provisions, called “stipulations,” to

be included in the leases for individual blocks. Bidders submit cash bids in sealed envelopes. On the

day of the sale, the bids are opened and read aloud. The highest cash bid for a given tract wins,

and—subject to government review to ensure it feels the bid represents the fair market value of the

lease—the high bidder receives the lease.

Brazil

In Brazil, the ownership of the soil is separated from the subsoil, and in this sense, all

mineral resources belong to the federal government.4 In 1953, Law No. 2004/53—later revoked by

Law No. 9,437/97—had already established that the federal government had the monopoly over oil

and gas (O&G) activities in Brazil. The same law also created Petróleo Brasileiro S.A. (Petrobrás)5

to carry out those activities on behalf of the government. This all happened in connection with a

government campaign called “The petroleum is ours,” an expression of a nationalist generation.

3 See generally Mark S. Barron, “Constitutional Protections for Mineral Interest Holders: Oil & Gas Regulation and the

Takings Clause,” 61 Rocky Mt. Min. L. Inst. (forthcoming 2015) (manuscript at 11-12, on file with the author). 4 See CRFB/88, article 176.

5 Article 61 of Law No. 9,478/97: “Petróleo Brasileiro S.A. – Petrobrás is a mixed-capital company linked to the

Ministry of Mines and Energy, which has as its objective the research, mining, refining, treatment, commerce, and

transportation of petroleum from wells, or schist or other rocks, or its by-products, of natural gas and of other

hydrocarbon fluids, as well as any other correlative activities or related subjects, in accordance with how they are

defined by law.” Petrobrás is a mixed-capital company in which the government owns 50.3 percent of the common

stock. In addition, the National Bank for Economic and Social Development (BNDS), which is a federal public

company, owns 9.9 percent of the common stock of Petrobrás. [information retrieved, on August 8, 2015, from

http://www.investidorpetrobras.com.br/en/corporate-governance/capital-ownership].

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In 1988, a new constitution was approved. It proclaimed that all natural resources located

within the Brazilian territory, continental shelf, territorial sea, and exclusive economic areas were

assets of the federal government.6 At this time, the Brazilian Federal Constitution of 1988

(CRFB/88) had explicitly prohibited—in article 177, paragraph 1—the government from assigning

or granting any kind of participation, in cash or value, to companies for the exploration of oil or

natural gas deposits. Although this prohibition was established, this rule did not apply to contracts

involving Petrobrás. Article 45, sole paragraph, of the Constitutional Act of Transitory Provisions7

(ADCT), exempted those risk contracts entered into with Petrobrás for oil prospecting that were

effective on the date of the promulgation of the CRFB/88 and consequently did not fall under the

prohibition of article 177, paragraph 1. Thus, the exploration for and production of oil and gas were

limited to Petrobrás until 1995, when the Brazilian federal constitution was amended. Constitutional

Amendment No. 9/95 modified article 177, paragraph 1 of the CRFB/88 to allow state-owned and

private companies to engage in oil and gas activities.

In 1997 the Petroleum Law (Law No. 9478/97) was enacted. Among other provisions, this

law regulates national energy policy and activities related to the oil and gas monopoly and

establishes the National Energy Policy Council (CNPE) and the National Agency of Petroleum,

Natural Gas and Biofuels (ANP). The Petroleum Law effectively abolished Petrobrás’ monopoly

over oil and gas activities in Brazil and opened up the market to other companies. With the

enactment of the Petroleum Law, exploration blocks began to be granted under the concession

regime.

In 1998, the Brazilian government promoted what was called Round Zero,8 entering into

concession agreements with Petrobrás without a bidding process.9 The purpose of this was to ratify

Petrobrás’ right to explore for, develop, and produce oil and natural gas in the areas that were

already under production and/or areas where major investments were made in exploration activities

at the time the Petroleum Law entered into force.10

As a result of Round Zero, ANP (representing

the federal government) signed with Petrobrás 397 concession contracts on August 6, 1998. 11

Finally, in 1999 Brazil held its first bidding round in which private companies were allowed

to bid for the right to explore for and produce oil and gas. During this time, the concession regime

was the only one in place. With the enactment of Laws Nos. 12,351/2010 and No. 12,226/2010, two

other regimes (production sharing and onerous assignments) were established for granting rights to

companies to explore for and produce oil and gas in Brazil.

Currently there are two regimes12

under which the Brazilian government may grant rights to

private companies for exploration and production of oil and gas: concession agreements and

6 See CRFB/88, article 20, V, VI, and IX.

7 Constitutional Act of Transitory Provisions (ADCT) is a group of constitutional rules established in order to ensure a

smooth transition from a previous constitutional regime to the new one. 8 Draft of the Concession Contract for Round Zero can be found at http://www.anp.gov.br/brasil-

rounds/round8/geral/contratos/ContratoR0.PDF and http://www.anp.gov.br/brasil-

rounds/round8/geral/contratos/ContratoR0_aditivo.pdf. 9 See Article 34 of Law No. 9,478/97.

10 See Articles 32 and 33 of Law No. 9,478/97.

11 Information retrieved on August 8, 2015, from http://www.brasil-

rounds.gov.br/Resultado_Rodadas/RESUMO_round0_resultados.asp. 12

There are three regimes applicable to the granting of rights to explore for and produce oil and gas in Brazil:

concession agreements, production sharing agreements, and onerous assignment agreements. The onerous assignment

agreement is not addressed above because it cannot be granted to private companies.

5

production sharing agreements (PSAs).13

Both of these agreements are awarded to private

companies through bidding rounds (competitive, sealed-bid auctions), which are held by the ANP.

The ANP is the federal regulatory agency for the oil, natural gas, by-products, and biofuels

sector in Brazil. This regulatory body was created to promote regulation, contracting, and

inspection of the oil and gas industry.14

The Brazilian bidding rounds are authorized by the National Energy Policy Council

(CNPE). Once a bidding round is approved by the CNPE, the ANP will publish information

regarding the bidding process on its website and in the Official Diary of the Union (DOU).

ANP Resolution No. 24/2013, article 3, describes the bidding process under the PSA, which

consists of the following steps:

I. Publication of the draft of the tender protocol;

II. A public hearing;

III. Publication of the final tender protocol;

IV. Qualification of the interested companies;

V. Submission of offers and judgment of bidding;

VI. Award of the PSA and approval of the bidding; and

VII. Execution of the contract.

These steps were similar to those established for the bidding process for concession agreements in

ANP Resolution No. 27/2011. However, on March 18, 2015, ANP published a new resolution

concerning the procedures for bidding for concession agreements and revoked its Resolution No.

27/2011. This new resolution, ANP Resolution No. 18/2015, inverts the steps of the bidding process

under concession agreements. According to the new rule, the decision on the winning bidders will

be made prior to the qualification of the companies. As of September 2015, Brazil is holdings its

13th bidding round, the first under the new rules established by ANP Resolution No. 18/2015.

The tender protocol sets forth the requirements and the blocks that are available for bid.

Companies are required to pay a participation fee for the sectors15

in which they have an interest in

bidding. Once the payment is made, the companies will receive the data package regarding each

sector for which they have paid a participation fee. The data package includes general information,

and when available, it will include thematic maps, public seismic data, public wells data, and public

gravimetry and magnetometry data. Companies may place a bid only on the blocks within a sector

for which they have paid the participation fee. ANP Resolution No. 18/2015 also stated that in

addition to the participation fee, the tender protocols for concession agreements may determine the

payment of fees regarding the costs of the bidding process.16

This fee had not been applied before,

and the ANP has not clarified yet which specific costs of the bidding process will be covered by this

fee.

Furthermore, companies must obtain financial,17

technical,18

and legal19

qualification from

the ANP. Proof of compliance with labor and tax regulations20

is also required from the companies.

13

See Article 23 of Law No. 9,478/97. 14

See Article 8 of Law No. 9,478/97. 15

In Brazil, the sedimentary basins are divided into sectors, and each sector has a number of blocks. 16

ANP Resolution No. 18/2015, article 14, paragraph 4. 17

See ANP Resolution No. 24/2013, article 19; ANP Resolution No. 18/2015, article 31. 18

See ANP Resolution No. 24/2013, article 18; ANP Resolution No. 18/2015, articles 32, 33, 34, and 35. 19

See ANP Resolution No. 24/2013, articles 20, 21, and 22; ANP Resolution No. 18/2015, article 29. 20

See ANP Resolution No. 18/2015, article 30 and tender protocols for the description of the documents necessary to

prove labor and tax regularity. For example, item 3.7 of the tender protocol for the 11th

bidding round (granting rights

6

The tender protocol of each bidding round lists the documents that the companies are required to

submit to be considered for qualification.21

Only qualified companies will be able to submit bids

during the bidding rounds granting rights to explore for and produce oil and gas under the PSAs. As

discussed above, qualifications of the companies are made after the submission of bids for

concession agreement and only by the bid winners. As a result, companies participating in the

bidding process for concession agreements will be able to bid without receiving prior approval of

their qualification status. This process may result in one member of a consortium not being

considered qualified, which in turn may affect the composition of the consortium and other

members playing a role that was not foreseen by them at the time of the bid.

During Public Hearing No. 01/2015, the ANP defended the position that having the

qualification as a step after the submission and judgment of bids will likely increase the

competition, and it will help the agency make better use of its human and financial resources. It also

benefits the companies by possibly reducing the costs of bidders that do not ultimately win the bids

and provides more time for the winning bidders to submit qualification documents. In addition, it is

possible for the companies to have a simplified process for technical qualification in cases in which

they already have existing concession contracts with the ANP and are requesting qualification

under the same modality as the one in which they are already operating.22

Interested companies may bid individually or as part of a consortium. Individual bids are to

be submitted to the ANP for each block in the sector, and the bids must be submitted in one sealed

envelope when they are all from the same consortium. If a company is also a part of another

consortium, bidding in the same sector, on separate blocks, the bids must be submitted in separate

envelopes.

Foreign companies can participate in the bidding process.23

However, if the company does

win a bid, the company will need to incorporate a subsidiary under Brazilian law with its

headquarters and administration located in Brazil.24

When determining the winning bid during licensing rounds that grant rights for exploration

and production under a concession agreement, the ANP will take into account, through the

allocation of scores and weights, the signature bonus (40 percent), the minimum exploratory

program (40 percent), and the local content (20 percent). Under a PSA, the principal consideration

under the concession contract) and item 3.7 of the tender protocol for the first bidding round (granting rights under the

first production sharing contract) state that national companies should submit the following documents to prove labor

and tax regularity: (a) Proof of enrollment in the Corporate Taxpayer Registry—CNPJ; (b) Joint Debt Certificate with

effect on federal taxes and the Federal Debt Roster, in charge of the attorney general of the National Treasury (PGFN);

(c) Certificate of Regularity of the Severance Premium Reserve Fund—FGTS; (d) Certificate of Pension Contributions

and Third Parties —RFB/INSS; and (e) Labor Debt Certificate with negative effect, in charge of the Labor Court. 21

When feasible, foreign companies also have to fulfill the same requirements as national companies with similar

documents to prove their qualification. 22

See ANP Resolution No. 18/2015, article 35. 23

Foreign companies participating in international bidding, when possible, will have to fulfill the same requirements

imposed on domestic companies by providing equivalent documents to prove technical capacity, financial competence,

and legal and tax compliance (article 32, paragraph 4 of Law No. 8,666/93). Those documents must be authenticated by

the respective consulates and translated by a certified translator. The Brazilian legal system requires foreign companies

participating in the bidding rounds to prove that they are organized under and operating in accordance with the law of

the foreign country in which they are organized (article 39, II of Law No. 9,478/97 and article 17, II of Law No.

12,351/2010). They also have to appoint a legal representative with the ANP to carry out acts and respond

administratively or judicially as required under Brazilian law. 24

See CF/88, article 176 paragraph 1; Law No. 9,478/97, article 39, IV and sole paragraph; Law No. 12,351/2010,

article 17, IV; ANP Resolution No. 18/2015, article 12, sole paragraph; ANP Resolution No. 24/2013, article 21.

7

given to each bid is the amount of the surplus to be paid to the government under the agreement,

taking into account the minimum percentage defined in the tender protocol.

2. How does the government determine the size of the area to be covered by the

agreement?

United States

By statute, DOI is limited to granting an area that does not exceed 5,760 acres, an area equal

to land three miles square. 43 U.S.C. § 1337(b). Since 1978, the secretary of the interior has had

authority to exceed that acreage if he or she finds “that a larger area is necessary to comprise a

reasonable economic production unit.” Id. No such finding has ever been made.

Brazil

The determination of the geographic area subject to the agreement is the responsibility of

the CNPE, which through the studies promoted by the ANP defines and demarcates the blocks.25

The size of the blocks varies according to the location of the areas. Since the fifth Brazilian

bidding round, ANP adopted the cell model, which is similar in concept to the model used in the

Gulf of Mexico and the North Sea. The ANP delineates the areas to be auctioned by designating

areas within the sedimentary basins, which are further divided into sectors, which are then divided

into blocks. Blocks are formed by combining a group of cells. Block sizes can vary from one sector

to another, but the block sizes are uniform for each sector.

Source: ANP

In this model, blocks have a predetermined size inside a sector. Offshore areas containing blocks in

shallow water (less than 400 meters deep) were offered between 170-190 km² (corresponding to six

cells); while blocks in deep water (between 400 and 1,000 meters deep) and ultradeep water were

offered between 650-770 km² (corresponding to 24 cells).26

25

See Law No. 9,478/97, article 2, VIII and paragraph 1 and article 8, II. 26

Retrieved from http://memoria.ebc.com.br/agenciabrasil/node/574495 and

http://www.petroquimica.com.br/edicoes/ed_249/ed_249a.html.

8

Source: ANP

3. What are the principal rights given to the company under the agreement, and what

rights are reserved by the government?

United States

Broadly speaking, the offshore lessee receives four sets of rights in the OCS lease

agreement form.27

First, the lease sets the period of time in which the lessee enjoys the rights under

the lease. By law, the lease must have a minimum initial period, usually called “the primary term,”

of five years. The primary term may be longer when needed to encourage exploration in deep water

or in unusual environmental circumstances.28

The maximum time allowed for a primary term is 10

years. Under current policy, leases in waters of 400 meters or shallower have five-year primary

terms. Leases in waters of 400 to 800 meters deep have primary terms of eight years, provided the

lessee drills a first well within the first five years of the lease. Leases in waters of 800 to 1,600

meters deep have primary terms of seven years, extended to 10 years if a well is drilled in the first

seven years. Leases in waters deeper than 1,600 meters have primary terms of 10 years.29

After the

primary term, the lease remains in force if the lessee is producing oil and gas, is drilling a new well,

or is “reworking”30

an existing well on the lease.31

A lease maintained by production, drilling, or

reworking is said to be in its “secondary term.”

Second, the lessee receives “the exclusive right” to “drill for, develop, and produce oil and

gas resources” within the leased area. Included in this exclusive right is the right to locate the

surface of the well outside the lease boundary and to drill directionally to reach a deposit of oil or

gas within the lease boundary.32

The rights to drill and produce are subject to substantial

27

The form currently used for new OCS leases is Form BOEM-2005 (October 2011). It is styled “Oil and Gas Lease of

Submerged Lands under the Outer Continental Shelf Lands Act.” We will refer to it as the “OCS Lease Form.” 28

30 C.F.R. § 556.37. 29

See, e.g., 80 Fed. Reg. 42529, 42530 (2015) (final notice of sale for Sale 246). DOI now even grants an eight-year

term for new leases in waters shallower than 400 meters if a well, begun in the first five years of the lease, targets an oil

or gas zone deeper than 25,000 feet below the seabed. Id. 30

“Reworking” means to take steps to maintain or increase production from an existing well, or to repair a well to

maintain an appropriate level of safety. 31

OCS Lease Form § 3. 32

OCS Lease Form § 11.

9

requirements, for these rights are subject to existing laws and regulations and, in some cases,

regulations enacted after the lease is issued. For example, a lessee cannot drill a well without first

receiving approval of an exploration plan or emplacing a production platform and beginning to

produce without first receiving approval of a development and production plan.33

Third, the lessee has the “right” to assign interests in its lease to a third party, although that

right is subject to the consent of DOI.34

Generally, DOI will allow the assignment if the company

that will receive the assignment is qualified to do business on the OCS. The company assigning the

lease (the “assignor”) remains responsible for fulfilling any obligations that “accrued” before the

assignment takes effect. For example, the assignor is responsible for paying royalties on oil or gas

produced before the effective date of the assignment.35

Fourth, a lessee may relinquish all or part of the lease, even before its primary or secondary

term has ended, by filing a relinquishment with DOI. The lessee remains responsible for all

obligations that accrued before relinquishment, including obligations to permanently plug all wells

drilled on the lease and to remove any structures emplaced to produce oil or gas.36

Most important to the topic of unitization is a right the lease does not give the lessee. The

lessee does not own the oil or gas existing “in place” within the lease boundaries. “A lease does not

grant lessees the ownership of minerals in place, and the law of capture applies to the development

and production of OCS minerals.”37

A molecule of gas originally beneath Lease A may be produced

through a well on Lease B. That molecule is not “owned” by either lessee until it reaches the

surface of a well. All the lease grants to the lessee is the right to an “equal” opportunity to develop

the gas from the reservoir that underlies Leases A and B.

While the OCS lease form grants significant rights to a lessee, it reserves several rights to

the government, some of which we will discuss here. First, the government reserves the right to

amend statutes and regulations. The lease is subject to those amendments, unless they “expressly

conflict with an express provision” of the lease.38

Second, the government has the right to receive

yearly rental payments while the lease is in force, until the lease begins producing oil or gas. At that

point, rentals end and “minimum royalty” and royalties begin.39

Third, the government reserves the right to receive royalties on oil and gas produced.

Typically, those royalties are a percentage of the oil or gas itself, or a percentage of the “value” of

the production. Traditionally, the OCS lease form reserved a royalty share of one-sixth for leases in

shallow water and one-eighth for leases in deeper water. More recently, DOI changed its policy,

increasing offshore royalty rates to 18.75 percent for new leases in all water depths.40

Fourth, the government reserves the right to inspect OCS facilities; enforce its regulations

for safety, environmental protection, and conservation of natural resources; suspend operations that

pose unnecessary risks; and terminate a lease for violations of the lease, the regulations, or the

statutes.41

33

OCS Lease Form § 9. 34

OCS Lease Form § 20. 35

30 C.F.R. § 556.62. 36

OCS Lease Form § 21. 37

45 Fed. Reg. 29280, 29281 (1980). 38

OCS Lease Form § 1. 39

OCS Lease Form §§ 4 and 5. 40

The change to an 18.75 percent royalty rate was first implemented in 2008 in Lease Sale 206.

http://www.boem.gov/BOEM-Newsroom/Press-Releases/2008/press0213.aspx. 41

OCS Lease Form §§ 12 and 13.

10

Fifth, the government reserves the right to allow third parties to come within the boundary

of the lease to conduct geophysical surveys or even to drill a well for geological information. The

third party may not produce oil from the well it drills, and it may not “unreasonably interfere” with

the lessee’s own operations.42

It is rare for a third party to drill a well on another’s lease for

geological information, but it is common to conduct geophysical surveys. Similarly, the

government reserves the right to allow a party operating a neighboring lease to locate its wells or

production platforms within the boundaries of another lessee’s lease. These rights of use and

easement allow the neighboring party to avoid environmentally sensitive sections of the seabed

when emplacing wells or platforms.43

Finally, the government reserves the right to allow a third

party to receive a right of way to lay a pipeline across the seabed of another’s lease.

Brazil

Private companies can obtain the right from the Brazilian government to explore for and

produce oil and gas in Brazil through concession agreements or PSAs. Onerous assignment

agreements are granted only to Petrobrás.

Concession Agreement The concession agreement is a type of contract in which the ANP grants rights to companies

to perform the activities of exploration, development, and production of oil and gas in a given

block. In this model, companies explore for and produce oil and gas at their own risk. The

companies own the hydrocarbons upon production. The company is responsible for the payment of

taxes and any corresponding share of royalties provided for under the law or the agreement.

In Brazil, concession agreements are granted in areas that are not considered as strategic and

also areas outside the pre-salt polygon. However, before the enactment of Law No. 12,351/2010,

areas in the pre-salt were granted under the concession regime.

The concession agreement has two stages: exploration44

and production (which also

includes development activities).45

The exploration phase can vary, lasting up to nine years, with

the duration determined under the tender protocol,46

while the production phase has a duration of 27

years.

Under the concession agreement, the concessionaires have the obligation to:47

a) Pay the government takes: signature bonus, royalties, special participation,

and payment for occupation or retention of the area;

42

OCS Lease Form § 19(a). 43

OCS Lease Form § 19(b). 44

Technical definitions are described in article 6 of Law No. 9,478/97.

[…]

XV – Research or Exploration: set of operations or activities aimed at evaluating areas, in order to

discover and identify oil or natural gas deposits;

45 Article 6 of Law No. 9,478/97 states:

[…]

XVI – Production: set of coordinated oil and natural gas extraction operations from a deposit and the

preparation for their conveyance;

XVII – Development: set of operations and investments intended to ensure the viability of production

activities in an oil or gas field;

46 The determination of this period takes into account the location of the block and its exploratory mode.

47 See Law No. 9,478/97, Chapter V, Sections I and V and Tender Protocols for granting concession contracts.

11

b) Perform a minimum exploratory program (work program);

c) Inform the ANP of the discovery of both oil and natural gas, as well as any

other natural resource it may locate during exploration;

d) Provide the ANP with a declaration of commerciality upon locating a

commercially viable deposit;

e) Use best industry practices to conserve reservoirs and other natural resources;

f) Fulfill local content obligations;

g) Remove the equipment that is not the object of reversion and to do

environmental restoration to the property in case of termination of the

concession; and

h) Indemnify the government for any claims it may incur as a result of the

activities of the concessionaire.

The concessionaires have rights, under the concession agreement, to:48

a) Explore for and produce hydrocarbons within the concession area;

b) Own the oil and natural gas after extraction;

c) Manage the import and export of hydrocarbons subject to the ANP’s

authorization;

d) Transfer the concession agreement to another company/companies with ANP

authorization;

e) Terminate the exploration in areas that do not justify development; and

f) Extend the duration of the exploration and/or production phase upon

approval from the ANP.

Production Sharing Agreement (PSA)

The PSA is often utilized in areas of “low” exploratory risk. In Brazil, this type of contract

is granted for the exploration and production of oil and gas in the pre-salt polygon49

and strategic

areas.50

These rights are limited to the exploration and production of hydrocarbons and specifically

exclude any other natural resource.

The PSA will be entered into between the government, through the Ministry of Mines and

Energy (MME), the ANP as a regulatory body and supervisor, Petrobrás, Empresa Brasileira de

Administração de Petróleo e Gás Natural S.A.–Pré-Sal Petróleo S.A. (PPSA),51

and the bid winners.

The PPSA represents the government’s interest in PSAs and bears no risk in the exploration

and production of the hydrocarbons. The role of the PPSA includes managing the contracts entered

into by the MME. In that capacity, the PPSA represents the government in matters related to the

consortium, acts as the government’s agent in operational committees, evaluates technical and

economic data, enforces the local content requirements under the contract, monitors and audits the

project, and provides its findings to the ANP.52

48

See Law No. 9,478/97, Chapter V, Sections I and V and tender protocols for granting concession contracts. 49 See article 2, IV of Law No. 12,351/2010–Pre-salt area: subsurface region formed by a vertical prism of undefined

depth, with a polygonal surface defined by the geographical coordinates of their apexes established in the annex hereof,

as well as other regions to be demarcated by Executive Branch act, according to the evolution of the geological

knowledge. 50

See article 2, V of Law No. 12,351/2010–Strategic area: region of interest for national development, to be demarcated

by Executive Branch act, characterized by low exploratory risk and high potential for the production of oil, natural gas,

and other fluid hydrocarbons. 51

The PPSA was created by Law No. 12,304/2010. 52

See article 4, I of Law No. 12,304/2010.

12

The PPSA also has a duty to oversee the sale of the government’s share of the hydrocarbons

under the PSA. Under this provision of the law, the PPSA is obligated to verify compliance by the

consortium concerning its obligation to develop a commercially viable field. In addition, the PPSA

monitors operational costs and sales, analyzes data provided by the consortium and the ANP, and

represents the government when entering into unitization agreements in pre-salt and strategic

areas.53

The rights under the PSA can be granted directly to Petrobrás under an exemption to the

bidding process or to other companies through the bidding process.54

Under the PSA, Petrobrás is

the sole operator, and it must also maintain a minimum 30 percent interest. However, Petrobrás can

increase its percentage of interest by participating in the bidding process.55

Petrobrás can assign a portion of the interest it has obtained through bid, but not its

minimum interest of 30 percent.56

A member of the consortium can transfer its interest in the PSA.

However, this transfer is subject to a first right of refusal by the others in the consortium.57

Assignment of rights and obligations must be expressly and previously authorized by the MME.

The government does not assume any risk under a PSA. However, the government, through

the creation of a specific fund allowed by law, can participate financially in a PSA, and through that

fund the government will be liable for its corresponding share of the risk as allocated under the

agreement.58

The companies that are parties to the PSA are obligated under the agreement to explore and

produce hydrocarbons at their own risk and cost. However, after the declaration of commerciality,

the companies are allowed to recover some of their cost by retaining a share of the oil, referred to as

cost oil. The first PSA model states that the amount of oil attributed to cost recovery is limited to 50

percent of the gross amount of production, calculated on a monthly basis for the first two years, and

30 percent of production for the following years. In the event the costs have not been recovered

within the first two years, the consortium may retain 50 percent of the oil produced the following

year, on a monthly basis and only under certain circumstances.59

The remainder of the oil

produced—profit oil—is split between the government and the companies according to the PSA.

The PSA is similar to the other types of agreements in terms of having two phases:

exploration and production. The law does not define the duration of the exploration phase; however,

the first PSA allowed four years for the exploration phase.60

The contract is for a period of 35

years.61

Under the PSA, the companies have the obligation to:

a) Enter into a mandatory consortium with Petrobrás and PPSA;62

b) Pay signature bonus, royalties, and a portion of the profit oil;

c) Perform a minimum exploratory program;

d) Inform the ANP of the discovery of both oil and natural gas, as well as any

other natural resource it may locate during exploration;

53

See article 4, II of Law No. 12,304/2010. 54

See article 8 of Law No. 12,351/2010. 55

See article 14 of Law No. 12,351/2010. 56

See article 31 sole paragraph of Law No. 12,351/2010. 57

See article 31, III of Law No. 12,351/2010. 58

Articles 5 and 6 sole paragraphs of Law No. 12,351/2010. 59

Information retrieved from the first PSA. 60

See item 10.1 of the first PSA. 61

See article 29, XIX of Law No. 12,351/2010. 62

See article 20 of Law No. 12,351/2010.

13

e) Provide the ANP with a declaration of commerciality upon locating a

commercially viable deposit;

f) Split the profit oil with the government on a monthly basis;

g) Use best industry practices to conserve reservoirs and other natural resources;

h) Fulfill local content obligations;

i) Remove the equipment that is not the object of reversion, and do

environmental restoration of the property in case of termination of the

concession; and

j) Indemnify the government for any claims it may incur as a result of the

activities of the company.

The companies, under the PSA, have the right to:

a) Explore for and produce oil at their own risk in the area granted;

b) Allocate the risk involved with their consortium partners;

c) Withdraw during the exploration phase, provided the minimum exploratory

program has been met;

d) Own a fraction of the oil produced (profit oil) upon establishment of

commercial viability; and

e) Reimbursement, through cost oil,63

for costs related to the exploration,

evaluation, development, and production upon establishing production in a

commercially viable field.

Onerous Assignment Agreement

Under the onerous assignment agreement, the government is allowed to assign directly to

Petrobrás the right to explore for and produce hydrocarbons, up to five billion barrels of oil

equivalent, in areas not located in the pre-salt.64

The activities performed by Petrobrás occur at its

own risk and expense. Petrobrás cannot assign its rights under an onerous assignment agreement.65

Upon obtaining production, Petrobrás owns the oil it has recovered, subject to a government royalty

and applicable taxes.

The onerous assignment agreement has a duration of 40 years, and under certain

circumstances, it can be renewed for an additional five years. In terms of the phases, it is similar to

the other types of agreements having two phases: exploration and production. The exploration

phase of this type of contract lasts up to four years, and the production phase lasts for the remaining

duration of the contract. Petrobrás is required to meet local content requirements under both the

exploration and production phases of the agreement.

The onerous assignment agreement terminates when Petrobrás recovers 5 billion barrels of

oil, the time as allotted under the agreement lapses, or other terms contained in the agreement itself

are met.

4. How does unitization change rights under an agreement?

United States

The basic idea behind unitization is to protect a reservoir that is common to more than one

lease. The dangers from which the reservoir is to be protected are drilling and producing practices

63

See article 2 II of Law No. 12, 276/2010. 64

See article 1 paragraph 2 of Law No. 12, 276/2010. 65

See article 1 paragraph 6 of Law No. 12, 276/2010.

14

that may lead companies to produce too quickly or to drill unnecessary wells in an effort to produce

more than the competitor across the lease line. To avoid that danger and serve that purpose, a

unitization agreement has a provision that “conforms” the provisions of the individual leases in the

unit to those of the unitization agreement. This means that the language of the unit agreement

trumps inconsistent language in the lease. For example, the language in a lease that allows the

lessee to enter upon the surface of the lease for drilling operations is extended to allow the operator

of the unit to come on the surface of any lease within the unit to drill a well on any other lease

within the unit. Stated more generally, the idea is that drilling or producing from any lease within

the unit is treated as drilling or producing from every lease in the unit; production from a lease from

the western side of a unit, for example, is treated as production from leases on the eastern side, and

all those leases are treated as being in their secondary term.

In American practice, however, protecting common reservoirs is not the only reason to

unitize leases. There are circumstances where it is more efficient to gather several leases into a unit,

especially a unit that can encompass an entire subsurface geological structure, to test which parts of

the structure might be best for more extensive drilling. These units are called “exploratory units.”

Balanced against the benefits of an exploratory unit are concerns that lessees in the unit may

unnecessarily “lock up” prospects within the boundaries of the unit, meaning that lessees in the unit

can hold on to those prospects without drilling them. Other companies might wish to develop these

prospects more quickly than the unit lessees wish to do.

To limit the risk of lockup, the OCS exploratory unit agreement includes the concept of the

“participating area.” Before the unit operator may begin producing the first successful well, it must

propose to DOI the outline of a participating area. That area is to include “all land reasonably

proven to be productive of unitized substances in paying quantities….”66

The participating area is to

be described “in parcels no smaller than ¼ x ¼ x ¼ blocks,” meaning that a parcel must contain at

least 90 acres. Only the leases that are within a participating area are entitled to share the production

from the well.

As further wells are drilled successfully, the participating area can be expanded, or

additional participating areas can be created.67

Participating areas can also shrink if lands are later

determined to be “proven not to be productive” of oil or gas. On the fifth and 10th anniversaries of

the initial participating areas, DOI will determine whether there are leases in the unit that have no

part of any participating area in them. If there is such a lease, that lease is “eliminated automatically

from the unit area.”68

Within participating areas that cover parts of two or more leases, production from wells

must be allocated to each participating lease. The model exploratory unit agreement contemplates

two methods of allocation. One is to look only at the surface acreage within the participating area.

For example, if 360 acres are in Lease A and 3,240 acres are in Lease B, then only 10 percent of the

production will be allocated to Lease A. The second method of allocation is volumetric. In this

method, reservoir engineers calculate the volume of oil and gas originally in place in the

participating area, measured in “net acre-feet,” and determine what percentage of the volume is in

each of the leases in the participating area.69

The volumetric method has been the overwhelming choice among unit participants, at least

in the Gulf of Mexico. Unfortunately, the most recent publicly available data on practice in the Gulf

66

Model Unit Agreement for Exploration, Development, and Production Units (“Model Unit Agreement”) § 11.1. 67

Model Unit Agreement §§ 11.2 & 11.3. 68

Model Unit Agreement § 13.1. 69

Model Unit Agreement § 12.1.

15

comes from testimony given in a hearing in 1982. At that time, there were 100 units in the Gulf. Of

those, 82 used the volumetric method, 17 used surface acreage, and one used a formula that

considered the volume originally in place as well as the relative shares of actual production during a

given period of time, giving equal weight to each factor.70

Brazil

Due in part to the relatively recent overhaul in Brazilian oil and gas law, the law has not

been fully developed in the area of unitization agreements. It was not until 1997 that the Petroleum

Law71

was promulgated regulating the national energy policy and activities in the oil and gas sector.

The Petroleum Law mentioned, on article 27 (currently revoked), that the unitization agreement

should be signed in case of oil fields extending over adjoining blocks with different

concessionaires. If the parties could not agree upon the terms of the unitization agreement, ANP

would have to make a decision regarding the allocation of the rights and obligations upon the

blocks. At this time, the rights to explore for and produce oil and gas were granted through

concession agreements.

In 2010, other laws were promulgated,72

creating additional methods—PSAs and onerous

assignment agreements—to award rights to companies to explore for and produce oil and gas in

Brazil. Article 27 of the Petroleum Law was then revoked by Law No. 12,351/2010,73

in which

there is a chapter dedicated to the unitization agreement.

According to the provisions of Law No. 12,351/2010, the parties have to enter into a

unitization agreement if there is a deposit that surpasses the contracted area or the area under

concession. The law now makes a reference to the “deposit” instead of mentioning the “field” when

addressing unitization. Among other provisions, this law also stipulates that the development and

production of the deposit that extends to another area will be put on hold until ANP approves the

terms reached by the parties in the unitization agreement. Under exceptional circumstances, ANP

can authorize the operation of the field not to be suspended.74

Brazil now has a mix of three different regimes in place: concession, production sharing,

and onerous assignment agreements. As a result, there are three different types of contracts

concerning exploration and production of oil and gas, each with different rules. Because of that, it

becomes a challenge for companies to harmonize the rules pertaining to their contracts when

entering into a unitization agreement.

70

Sun Oil Co., 91 IBLA 1, 29 (1986). 71

Law No. 9,478/97. 72

Law No. 12,351/2010; Law No. 12,226/2010. 73

Law No. 12,351/2010, which regulates the exploration and production of oil, natural gas, and other fluid

hydrocarbons under the production sharing regime in the pre-salt areas and in strategic areas; it creates the Social Fund

—FS—and regulates its structure and funding sources and amends provisions of Law No. 9,478, of August 6, 1997. 74

See article 41 of Law No. 12,351/2010.

16

Example of Areas Under Different Regimes

Source: http://www.petrobras.com.br/pt/nossas-atividades/areas-de-atuacao/exploracao-e-producao-de-

petroleo-e-gas/marco-regulatorio/

Brazilian law provides the minimum requirements that a unitization agreement must contain,75

but

it does not provide all the guidelines for the companies to make the different rules compatible.

Once the companies enter into a unitization agreement for the areas that contain the shared

deposit, the unitization agreement may change some of the rights that were previously granted to

those companies. Those changes may occur because in some cases the areas in the shared deposit

are under different types of contracts. Consequently, the unitization agreement will have to

accommodate the rights and obligations of those areas, creating an agreement that pertains to just

the shared deposit. In regard to the divisible obligations, the rules will be applied according to the

75

ANP Resolution No. 25/2013, article 13, states, “The Individualization of Production Agreement (Unitization

Agreement) shall contain at least the following information:

I - the identification of the shared deposit;

II - the definition of individualized area with the delimitation of the polygons;

III - the operator for the shared deposit;

IV - rights and obligations of the Parties involved;

V - the participations in the shared deposit;

VI - the possibility of Redeterminations with the criteria, conditions, terms, limits, and quantity that

will be applied;

VII - local content rules;

VIII - the obligations of each Party for payment of their participations, Government Revenue and

Third Party;

IX - the duration of the individualization of production agreement;

X - the dispute settlement mechanisms;

XI - the Development Plan for the Shared reservoir object of the unitization agreement.”

17

parties’ original contracts. However, the terms of the indivisible obligations will be set in

accordance with ANP regulations.76

Some of the more contentious issues that require agreement by the companies include:

a) The percentage of participation in the shared deposit for each part—

Article 13, paragraph 2, of ANP Resolution No. 25/2013 states that the

preferred method to be used to define the participation interest of the parties

is the proportion of the original volume of oil equivalent in the shared deposit

contained in each of the areas under the contract. However, the parties can

submit other criteria for evaluation and approval by the ANP. Some of the

other methods used in establishing the parties’ interest in the shared deposit

include the parties’ respective shares based upon their surface interest in the

shared deposit, relative volume in the reservoir, relative volume of the pore

space, volume in place, and recoverable volume. Although other methods can

be utilized to define the parties’ interest in the shared deposit, when

analyzing all five “individualization of production agreements” (AIPs)77

approved by ANP (Albacora and Albacora Leste,78

Mangangá and

Nautilus,79

Camarupim and Camarupim Norte,80

Lorena and Pardal,81

and

Xerelete and Xerelete Sul82

), the original volume of oil equivalent was the

method applied in those AIPs, suggesting that this is the criterion that

companies prefer to use offshore of Brazil.

b) Royalties—Under the different types of contracts, there are different royalties

retained by the government. Under the concession agreement, the royalties

are usually 10 percent, subject to reduction to a minimum of 5 percent,

depending upon the risk involved, while under the PSA, the royalties are

usually 15 percent, and the royalties retained by the government under an

onerous assignment agreement are usually 10 percent. An illustration of the

difficulties posed by differing royalty rates has already arisen. There is a

shared deposit involving the fields of Lula (under concession agreement), Sul

de Lula (under onerous assignment agreement), and an area that was not

granted yet (no contract). On June 19, 2015, in response to this circumstance,

76

See article 13, paragraph 6 of ANP Resolution No. 25/2013. 77

The term AIP is explained in the answer to Question 6 below. 78

It was the first AIP approved by ANP. The approval for the AIP involving Albacora (concession agreement No.

48000.003703/97-02) and Albacora Leste (concession agreement No. 48000.003895/97-67) was made on December 28,

2007, through RD 823/2007. 79

AIP involving Mangangá (concession agreement No. 48000.003560/97-49) and Nautilus (concession agreement No.

48000.003552/97-11) was approved by ANP on October 7, 2008, through RD 737/2008. 80

AIP involving Camarupim (concession agreement No. 48000.003535/97-00) and Camarupim Norte (concession

agreement No. 48610.010724/2001) was approved by ANP on June 2, 2009, through RD 472/2009. 81

AIP involving Lorena (concession agreement No. 48000.003807/97-08) and Pardal (concession agreement No.

48610.009227/2002) was approved by ANP on December 15, 2009, through RD 1190/2009. In 2012, through RD

368/2012, ANP approved the concessionaires of Pardal-UTC Engenharia S.A. and Potióleo S.A to transfer their rights

and obligations (participation of 50 percent and 50 percent, respectively) to Petrobrás. A new concession agreement—

48610.009227/2002A (BT-POT-10A)—was also issued to the Pardal field. Since Petrobrás now owns 100 percent of

both fields, it was then necessary for Petrobrás to sign a CIP instead of an AIP. This CIP for the shared deposit in the

Lorena and Pardal fields was approved by ANP on January 22, 2015, in RD 45/2015. 82

AIP involving Xerelete (concession agreement No. 48000.003544/97-92) and Xerelete Sul (concession agreement

No. 48610.010727/2001) was approved by ANP on October 31, 2013, through RD 1152/2013.

18

ANP issued guidelines through RD 425/2015 for the preparation of the AIP

involving these fields that defined royalties of 15 percent for that area that

has not been granted.

c) The company that will act as the operator in the shared deposit—The

unitization agreement will indicate the operator of the shared deposit,

according to article 33 of Law No. 12,351/2010. However, because Petrobrás

is statutorily required to be the sole operator under a PSA, the law is unclear

about whether Petrobrás is also required to be the sole operator for all the

shared deposits involving pre-salt or strategic areas. It is unreasonable to

conclude that Petrobrás must be the operator for all these areas. The

prevailing understanding is that any company can be the operator in the

shared deposit.

d) Allocation of costs and reimbursements—Some of the incurred costs and

investments that were made by one party prior to signing the unitization

agreement can bring discord between the parties at the time of discussing

reimbursements. Sometimes one party can allege that the incurred costs were

part of the risk of the activity or they were not part of the decision in which

the expenditure was generated.

e) Special participation—It is the amount payable in case of a production of a

large volume of oil. Special participation is applicable only to concession

agreements and not under PSAs or onerous assignment agreements. In the

case of a shared deposit, the special participation is based on the net revenue

of the production and the whole inspected production volumes of each field.

The unitization agreement will define the allocation of each party’s share

based on the net revenue of production in the base period and consequently

the special participation. Special participation of the shared deposit that

passes to areas under different regimes should be designated only to the

portion of the field under the concession agreement, and it should be

segregated from the total shared deposit: the inspected production volume,

the gross revenue of production, and the expenses incurred in exploring and

producing the area.83

f) Local content—There are different rules for local content under the different

types of contract. Even under the concession agreement, depending upon the

bidding round of the contract, there is a possibility that there are different

percentages of local content, due to local content being one of the criteria

used when considering the bid. The AIP involving Camarupim (block BES-

100) and Caramupim Norte (block BM-ES-5), approved by ANP in RD

599/2009, provides an example. Although this AIP involved areas under the

same regime—a concession agreement—those agreements had different rules

pertaining to local content. For block BES-100, the minimum percentage of

local content to be fulfilled was 0 (zero), while for block BM-ES-5, the

parties had to fulfill the minimum of 30 percent of local content. Given the

difference in the minimum percentage of local content for the areas under

this unitization agreement, the AIP required that the parties should observe

the minimum of 20.85 percent for the contracting of goods and services

83

ANP Resolution No. 12/2014, article 9, paragraphs 1 and 2, a, b, c.

19

related to the operations of the shared deposit. This minimum of 20.85

percent was reached by using the weighted average (“media ponderada”) of

the minimum percentage of local content that was required for blocks BES-

100 and BM-ES-5.

Source: ANP

In conclusion, due to the complex nature of the three different types of agreements, and the

relatively new implementation of Brazilian oil and gas laws, unitization agreements remain an

unsettled issue in the Brazilian regulatory framework. Nevertheless, the Brazilian government has

been working to create rules to address these concerns.

5. How large an area may be governed by one unitization agreement?

United States

By statute, the secretary of the interior is given broad discretion to issue regulations for,

among other things, unitization.84

The statute does not limit the size of the area governed by a

unitization agreement. Through regulation, the secretary has not set a numerical limit on the acres

or leases that can be included in a unit agreement. The regulation does, however, limit the size of

the unit to the fewest leases “that will allow the lessees to minimize the number of platforms,

facility installations, and wells” needed for efficient development of the area.85

Although two is the

minimum number of leases needed to unitize an area, unit areas can be significantly larger. For

84

43 U.S.C. § 1334(a)(4). 85

30 C.F.R. § 250.1302(c).

20

example, the Santa Ynez unit, in the Santa Barbara Channel offshore of California, is composed of

16 leases.

Source: http://www.boem.gov/pacific-ocs-map/

In the Gulf of Mexico, as of June 2013, 593 leases were unitized under 186 unit agreements.

Although a few of those units are composed of more than 10 leases each, the average for the Gulf is

approximately three leases per unit. 86

Brazil

There is no limit to the size of the area under the unitization agreement. The size of the

shared deposit is what determines the area that will be governed by the unitization agreement.

6. May the government require two companies to sign a unitization agreement?

United States

Yes. DOI may compel its lessees to join a unitization agreement.87

But it may do so only if

the leases are underlain by a common reservoir of oil or gas, and if DOI determines that operations

by competing lessees might damage the reservoir, result in unnecessary drilling, or interfere with

the rights of the parties to produce a fair share of the oil or gas in the reservoir.

Additionally, DOI may compel unitization to protect its royalty interest in the leases.88

An

example will clarify what the regulation means. Suppose, for example, that a reservoir of oil

underlies two leases. Suppose further that geologists have determined that each lease’s share of the

86

Federal Offshore Unitization An Overview - Gulf of Mexico OCS Region. Author: Mark Hanan;

http://www.bsee.gov/uploadedFiles/BSEE/BSEE_Newsroom/Speeches/2013/OCSAB_2013_Federal%20Offshore%20

Unitization-An%20Overview.pdf. 87

30 C.F.R. § 250.1301(b). 88

30 C.F.R. § 250.1301(b)(3).

21

oil originally in place happens to be 50 percent. One lease has a royalty rate of only 12.5 percent,

the other 20 percent. It is in the government’s interest to have as much of the reservoir’s oil

produced from wells on the lease with the 20 percent royalty rate. But if the lessee of the 12.5

percent lease begins operations first or is producing 80 percent of the oil, DOI will perceive that it

will make less money in royalties unless it forces the parties to unitize the reservoir.

DOI has compelled the creation of 18 units.89

A few of them have been subject to

administrative appeal and judicial challenge.90

From DOI’s regulations and this handful of cases, some key points emerge about compelled

unitization in the OCS. First, the mere fact that a common reservoir underlies two or more leases

does not mean that the reservoir must be unitized. Instead, DOI must find that, unless a unit is

compelled, lessees will engage in unneeded drilling or will drain the reservoir in a way that will

unnecessarily leave oil or gas in the ground.91

Second, DOI need not first exhaust other methods of protecting the reservoir before

compelling a unit. For example, in Placid Oil Co., the common reservoir in question was primarily

oil, but at the top of the reservoir there lay a “cap” of natural gas. The expansion of that gas

provided the energy to push oil into the wellbores in the reservoir. Underneath the oil lay water,

which rose into the reservoir as the oil above was produced. As it happened, however, nearly all of

the gas cap lay on Placid’s side of the lease line. Placid had an incentive to produce the gas rapidly,

but to do so would have prematurely reduced the energy needed to produce the oil. Placid argued

that it first should have been allowed to limit its production of gas in lieu of unitization. DOI ruled

that the law “does not require that unitization be imposed only as a last resort.”92

Indeed, DOI often regards unitization as the method of first resort. In Tenneco Oil Co., DOI

encountered a pair of large natural gas reservoirs under five lease blocks, into which 50 producing

wells had been drilled. As the reservoirs were produced, each of the wells detected a corresponding

drop in pressure, indicating that the wells were all in what reservoir engineers call “pressure

communication.” Although Tenneco Oil Co. did not pose the risk that rapid production might

reduce the ultimate total production from the reservoirs, it did create an incentive for the competing

lessees to drill additional wells that would merely hasten the depletion of the reservoirs, not enlarge

their ultimate production volumes. DOI found unitization the ideal solution.

Unitization is particularly appropriate in a situation involving a large common

reservoir where, as here, the operator of a lease overlying a small part of the original

reserves drills early and aggressively along the lease boundary. In the absence of unitization,

development of the leases overlying the remainder of the reservoir would have become a

89

Federal Offshore Unitization An Overview - Gulf of Mexico OCS Region. Author: Mark Hanan;

http://www.bsee.gov/uploadedFiles/BSEE/BSEE_Newsroom/Speeches/2013/OCSAB_2013_Federal%20Offshore%20

Unitization-An%20Overview.pdf. 90

The most contentious was the compelled unitization of the so-called “P sands” beneath Vermilion blocks 320 and

321. This resulted in three published opinions of the Interior Board of Land Appeals, an unpublished ruling of an

administrative law judge, and one judicial opinion. Sun Oil Co., 42 IBLA 254 (1979); Sun Oil Co., 67 IBLA 80 (1982);

Sun Oil Co., 91 IBLA 1 (1986), aff’d sub nom. Clark Oil Prod. Co. v. Hodel, 667 F.Supp. 281 (E.D. La. 1987). Other

cases have addressed the unitization of the “J2 sands” underneath the Eugene Island block 330 field, Texaco, Inc., 51

IBLA 332 (1980); the “C6-RA sands” and the “JS A-1 sands” underneath Ship Shoal blocks 206 and 207, Placid Oil

Co., 46 IBLA 392 (1980); and the “3,200-foot sands” and the “3,500-foot sands” beneath West Cameron blocks 532,

533, and 534, and East Cameron blocks 281 and 298, Tenneco Oil Co., 57 IBLA 85 (1981). More recently, Taylor

Energy Co., 148 IBLA 286 (1999), addressed an unsuccessful attempt by a lessee to compel a unit over the objections

of the department’s Minerals Management Service. 91

As noted above, the department may also compel a unit to protect the government’s royalty interests. 92

Placid Oil Co., 46 IBLA at 395.

22

race designed to protect the opposing interest[s] of the lessees. Development plans would

have been geared to the protection of correlative rights instead of being oriented toward the

maximum production of hydrocarbons from the common reservoir with the least number of

wells. Accordingly, unitization prevented the drilling of unnecessary wells and was in the

interest of conservation.93

Third, the greatest policy challenge in compulsory unitization is not whether to compel a

unit, but how to allocate the production. In voluntary units, most lessees have agreed to allocations

based on the original volume of oil or gas in place. But that formula is not a right guaranteed by the

lease itself, for the lessee receives not ownership of the oil or gas in place but only a fair

opportunity to produce it.94

Should some reward be given to the first lessee to establish production

in the common reservoir? Should some reward be given to the one with the luck or ingenuity that

has allowed it to drill the most productive wells?

DOI first confronted this question in Texaco, Inc. There, a common reservoir had been

penetrated by 13 producing wells. The first began production in January 1974, the last (Texaco’s) in

December 1976, nearly three years later. DOI allocated production based on original gas in place,

giving Texaco less than 4 percent of the production. But Texaco’s well was prolific, producing 26

billion cubic feet of gas before it “watered out” three years later. Noting the high national demand

for natural gas, Texaco argued that original reserves should not be the sole factor used in the

allocation, and that the relative share of production should be included and given equal weight.95

On appeal, the Interior Board of Land Appeals disagreed. The board noted that Texaco’s well was

the last of 13, and no evidence showed that Texaco’s well had increased the total ultimate recovery

from the reservoir.96

The board concluded there was no persuasive reason to depart from an

allocation based on the original gas in place.

At about the same time, however, DOI did use a hybrid allocation for another compelled

unit. In Sun Oil Co., DOI addressed a common reservoir in which eight wells were producing, three

owned by Sun Oil, five by Shell on the other side of the lease line. Shell proposed to drill additional

wells into the reservoir. DOI decided the additional drilling was unnecessary, would not increase

the total ultimate production from the reservoir, and posed unneeded risks to the environment. It

compelled a unit.

DOI then turned to the question of allocation. DOI determined that 81 percent of the

reservoir’s reserves underlay Shell’s lease, 19 percent underlay Sun’s. But during a six-month

period prior to unitization, Sun’s wells had produced 55 percent of the total production. DOI

decided Sun should be rewarded in the allocation for the superior productivity of its wells. DOI

chose a formula that gave some weight to well productivity, resulting in Sun receiving 32 percent—

not 19 percent—of the total production from the reservoir.97

Shell and Sun both acquiesced to DOI’s decision to use a hybrid formula instead of relying

solely on reserves originally in place. Shell defended DOI’s outcome; Sun challenged DOI’s failure

to give greater weight to the productivity of Sun’s wells. Because of the positions of the parties in

the administrative appeal, the Interior Board of Land Appeals did not have occasion to elaborate on

93

57 IBLA at 88. 94

See, e.g., Sun Oil Co., 91 IBLA at 32 (“Admittedly, as a historical matter, the law of capture recognized fee

ownership as providing, at most, merely an equal opportunity to produce from a common reservoir.”) (emphasis in

original). 95

51 IBLA at 344-45. 96

51 IBLA at 354-55. 97

91 IBLA at 23-24.

23

when and why it is appropriate to reward well productivity in the allocation of production under the

unit agreement.

Brazil

Yes. Companies must sign a unitization agreement once it has been determined that there is

a deposit that extends beyond the limits of the block in which it was granted the right to explore for

and produce oil and gas.

The rule of capture states that the oil or gas, extracted from a well drilled in an area in which

one has the right to explore for and produce it, will be owned by the one that first extracts it even if

it migrates from another owner’s property. According to José Alberto Bucheb,98

since the

introduction of Brazilian Petroleum Law No. 9,478/97, article 27 (which has since been revoked), it

was stated that once it was determined that a reservoir extended beyond the limits of the blocks

under concession, the parties involved would have to enter into a unitization agreement. That

same position remained with Law No. 12,351/2010, article 33, which rewrote article 27 of the

Petroleum Law, as ANP Resolution No. 25/2013. So, in Brazil, there is a practically

unanimous understanding that the rule of capture is not allowed under interpretation of the

applicable law. Article 33 of Law No. 12,351/2010 states, “The unitization procedure for

production of oil, natural gas and other fluid hydrocarbons shall be implemented when it is

observed that the deposit extends beyond the block granted or contracted under the production

sharing regime.”

According to Law No. 12,351/2010 and ANP Resolution No. 25/2013, the concessionaire or

contractor must notify the ANP about the existence of a shared deposit within 10 days of the

discovery. The ANP will notify the parties involved, after which they can confirm or deny the

presence of the deposit that extends beyond the boundaries of their contracts. In the event

it is confirmed that there is a deposit extending into adjacent areas, the ANP will set up a timeline

for the parties to enter into a unitization agreement involving the shared deposit. This timeline will

be decided by the ANP after it takes into account the different conditions under which the

unitization agreement will be finalized. Unitization agreements involving different parties on areas

under different contracts, or areas that were not yet granted, are more complex and consequently

require more time to complete the agreement than in areas under the same regime. The unitization

agreement does not extend to the entire block but is limited to the deposit in which the parties have

a shared interest.

The unitization process usually encompasses three stages: pre-agreement, unitization

agreement, and redetermination. The pre-agreement is not required, but it is possible for the parties

to enter into it due to the complex nature of a unitization agreement and the costs and time involved

when determining the allocation of the shared reservoir among the parties. The pre-unitization

agreement is usually made before the declaration of commerciality, and at that time, the companies

may not have all of the information required to enter into a unitization agreement. Because of that,

the primary reason for the pre-unitization agreement is to acquire additional data to make a better

assessment of the shared reservoir in order to define the percentage owned by each of the parties. In

addition, it addresses the confidential nature of the information that is to be exchanged by the

parties concerning their findings in the shared deposit. If there is a pre-unitization agreement, the

companies are required to send a copy of it along with the discovery evaluation plan to the ANP.99

98

Telephone interview with José Alberto Bucheb, general manager, Corporate University at Petrobrás (February 9,

2015). 99

See Resolution No. 25/2013, article 7, sole paragraph.

24

In Brazilian practice, the parties will sign either an individualization of production

agreement (AIP)100

or an individualization of production commitment (CIP).101

The former is used

when there are different companies or consortiums owning other than identical interests in blocks

containing the shared deposit. The latter is used when the same companies or consortiums own

identical interests, under different legal regimes, in separate blocks containing the shared deposit.

The unitization agreement involving shared deposits situated outside the pre-salt polygon or

outside areas that are considered strategic and that extend to areas not yet granted will be signed

with the ANP (representing the government).102

However, on those areas that were not yet granted

and have the shared deposits extending into the pre-salt or in a strategic area, the PPSA will be the

one representing the government when signing the unitization agreement.103

Once the unitization agreement is signed, the parties submit it to the ANP for approval. This

agreement is attached to the parties’ original contract that granted the right to explore for and

produce oil and gas in the area. If the parties who have an interest in the shared deposit cannot agree

upon the terms of the unitization agreement, the ANP will set the terms for them.104

The parties will

then be required to enter into the agreement as determined by the ANP. Failure of the parties to

participate in the unitization agreement results in the termination of the contract for the

noncomplying party for the entire block.105

However, it is important to note that once the ANP has

set the terms of the agreement, this is an administrative decision subject to judicial review.

Once the unitization agreement is in place and it is necessary to revise the percentage of

participation interest of the parties that was previously set in the unitization agreement, the parties

will use what was established under the terms for the redetermination. The adjustment of the

participation interests is based on the acquisition of new data that results in a better understanding

of the shared deposits. The methods for reaching these redeterminations can be freely selected by

the companies in the unitization agreement. The companies will usually stipulate in the unitization

agreement the situations in which they can call for the redetermination, the time frame for the

redetermination to occur, the number of the determinations allowed, and the methods for resolving

disputes. They should also address whether or not the redetermination will have a retroactive effect.

However, in the case of redetermination, there is no retroactivity regarding government takes on the

payments already made.106

Although redeterminations are usually stipulated to by the companies, the ANP can also

require redeterminations when technically justifiable. In theory, decisions involving

redeterminations are retroactive to the beginning of the unitization agreement. Because of that, it

can be a difficult task for companies to review all contractual participation after years of exploration

activities. Oftentimes, this can result in the immediate shift in expenses already incurred from one

party to another, while the gains from production are usually distributed to the benefiting party

through future increases in production.

While a redetermination agreement seems like a practical means of allocating the parties’

rights and responsibilities after acquiring further data from production, there are several

disadvantages to redetermination agreements that can lead to a time-consuming and expensive

100

See article 4 of the ANP Resolution No. 25/2013. 101

See article 6 of the ANP Resolution No. 25/2013. 102

See article 5, paragraph 1 of the ANP Resolution No. 25/2013 and article 36 of Law No. 12,351/2010. 103

See article 5, paragraph 2 of the ANP Resolution No. 25/2013 and article 37 of Law No. 12,351/2010. 104

See article 29 of the ANP Resolution No. 25/2013 and article 40 of Law No. 12,351/2010. 105

See article 34 of the ANP Resolution No. 25/2013 and article 40 sole paragraph of Law No. 12,351/2010. 106

See ANP Resolution No. 25/2013, article 26 sole paragraph.

25

process. Redetermination of a unitization agreement requires a vast amount of technical data and

the use of experts to establish the revised allocation. The parties do not always agree upon the

findings or experts, which can result in legal disputes.

7. How long will a unitization agreement remain in force?

United States

A unitization agreement remains in force until no more oil or gas is being produced from a

well within the unit and no more drilling is occurring.107

A unitization agreement may also remain

in force without production or drilling if DOI has granted a suspension of operations or suspension

of production.108

If none of these conditions is satisfied, then the unit agreement expires by its own

terms. A unitization agreement may also be terminated by DOI upon a request by the owners of “a

majority of the working interests in each lease or portion thereof committed to this Agreement.”

DOI is empowered to disapprove the request.109

If a unitization agreement expires or terminates, the individual leases comprising the unit

will also expire unless (1) the given lease is still in its primary term, (2) the lessee begins (or

continues) drilling or well-reworking operations on the lease within the time permitted by

regulation, or (3) DOI grants a suspension of operations under the regulations.110

Brazil

The duration provided for in the unitization agreement should take into consideration the

original duration granted to each party under its individual agreement. The ANP, at its sole

discretion, may extend the duration of the phases in the areas of the shared deposit when the parties

do not have similar timelines in their original contracts.111

Final Observations

Much of Brazil’s law governing unitization is yet to be developed. At present, however,

Brazil and the United States differ on a main point of policy. Brazil requires unitization of all

reservoirs that are found to be common. The United States will require unitization only if a

common reservoir is “competitive,” meaning that there is at least one well on each side of the lease

line. And even then, the United States will compel unitization of a competitive reservoir only if it is

needed to serve some greater good: maximizing ultimate recovery of oil or gas, preventing

unneeded drilling, or ensuring the government’s royalty interest is protected.

On the issue of how production will be allocated, one can predict that it is in the AIPs—

those unitization agreements governing situations when the interests of the parties on each side of

the line are not identical—that conflict may arise over whether more than just the original share of

reserves should be considered. The fact that Brazil requires unitization of any common reservoir

suggests that Brazilian law is already tilted toward the view that those that receive PSAs or

concession agreements have a right to the oil and gas within their agreement area, not just to a fair

opportunity to produce it. And while ANP Resolution No. 25/2013 indicates that the agency might

consider alternatives, allocations based on original oil and gas in place are preferred. So Brazilian

107

Model Unit Agreement, Article XVI, paragraph 16.1. 108

Id. See also 30 C.F.R. § 250.1301(g). 109

Model Unit Agreement, Article XVI, paragraph 16.2. 110

30 C.F.R. § 250.1301(f). 111

See ANP Resolution No. 25/2013, article 13, paragraphs 4 and 5.

26

law may be more resistant than American law to rewarding well productivity to those that discover

the reservoir in the first instance.

ContactsL. Poe Leggette Denver pleggette@bakerlaw.com T 303.764.4020

Laura J. McMahonHouston T 713.646.1301 lmcmahon@bakerlaw.com

Sashe D. DimitroffHoustonT 713.646.1320 sdimitroff@bakerlaw.com

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