Top issues faced by the Brazilian Oil & Gas industry

The trends created by the events of the passing years and the impact they may have in the future

In 2008, international oil prices crossed the psychological barrier of 100 US$/barrel. After a subsequent period of volatility, prices resumed an upward trend that led to years of high prices and to an outstanding period of the world Oil & Gas (O&G) industry. The recent events could hardly be predicted nor mitigated. International oil prices crash are reshaping the global O&G industry. By the end of 2014, the expectation was that the industry was facing a short-lived low-price environment. In 2015 and 2016, the acceptance of the lower price levels resulted in market participants retrenching, cutting costs, and capital projects delays to preserve cash flows. The prolonged effect of the price crisis drove the industry to reconsider its operations. In 2017, the oil prices averaging US$ 54 per barrel, thus more than 10 dollars increase of the average of 2016 (US$ 43), represented the first annual rise since 2012 (BP Statistical Review of World Energy 2018). Even though this increase in the oil price represented a partial relief to oil companies, and probably also contributed to the success of last bid results in Brazil, companies are still adapting their investment plans to face this new scenario, full of uncertainties and working to keep costs down .

This section is not a predictive statement of the future of what the oil and gas sector will experience. It is, however, a content of the important and unfolding trends that may influence our way forward in the years ahead. In this document, we explore the trends created by the events of the passing years and the impact they may have in the upcoming years.

Investment optimization and cost reduction

In face of lower oil prices, comparing to the levels before the 2014 crisis, O&G companies must wisely keep choosing carefully investments and maintain costs down

Oil companies used to have a tendency to overinvest due to the notion that this industry provides high profit margins. Even though after the 2014 crisis the prices of goods and services in the upstream also decreased significantly, and that in 2017 the crude price had an important rise, oil companies globally are still working to keep its costs down, and so occurs in the Brazilian oil sector. The key question is how to optimize investments, taking into account the new oil prices landscape (still way below 100 dollars per barrel), in order to try to maximize shareholder value.

Apart from balancing cash flows, this new environment will likely require new capital strategies and greater dynamism in the capital decision-making cycle of an O&G company. Companies, and specially shareholders and stakeholders need to be confident that the money directed towards its portfolio of projects is being treated responsibly.

In order to attract and secure long-term investment, companies must optimize investments. It is an imperative when mitigating the risks associated to the development of O&G projects. It is important to keep in mind that, in order to optimize a portfolio one must also consider the possibility of divesting certain assets, which do not necessarily contribute to the company’s core objectives.  

In particular, Brazilian oil and natural gas production increase will mainly come from pre-salt resources, which still present high Exploration & Production (E&P) costs. Offshore E&P activities will keep requiring cost reduction strategies to face lower oil prices levels and avoid the return of inflationary pressure, as occurred prior to 2014. Petrobras has been successful in cost reduction. To exemplify this success, when it comes to drilling costs in Lula and Sapinhoá fields (the top producers pre-salt fields), which usually represents 40%-60% of offshore projects’ total cost, Petrobras achieved a 57% reduction time in drilling and well completion (Petrobras, 2016). Despite the cost-cutting efforts, the dramatic fall in oil prices can still hinder the economic viability of deep-water projects. Thus, it is of particularly importance to keep investing not only in technological improvements, but also in rethinking the current offshore business model, in order to identify other barriers to cost reduction. In this manner and in a global perspective, the International Energy Agency (IEA) World Energy Report 2018 highlights that oil companies are progressively believing in digitalization (E.g. big data analytics and automation technologies) as a path for further cost reduction.

Bidding Rounds Agenda and Production Sharing Agreements

Government must be careful not to deter the foreign investment needed to develop the O&G sector

Between 1999 and 2008 the Government held annual bidding rounds, offering exploration opportunities with varied characteristics. It is worth noting that the regularity and predictability of the auctions resulted in a period of strong regulatory stability and steady growth of the Brazilian petroleum industry.

On the other hand, the remarkable episode of the discovery of a new oil province with low geological risk and an extremely high potential located in the Brazilian Pre-Salt layer, brought back to the arena the debate about the regulatory framework currently in place and its applicability to the newly discovered reserves. Two unfolding consequences of this episode have significantly affected the rhythm of bidding rounds in Brazil: (i) the scarcity of offshore exploration areas offered to the market in 2008-2012, and (ii) the creation of a new regulatory framework for the Pre-salt (subsalt reserves) and strategic areas, typified by the introduction of the production sharing agreements (PSA).

(i)  Scarcity of offshore exploration areas offered to the market in 2008-2012


Brazil retook its trajectory of bidding rounds, but large areas remain virtually unexplored and are anxiously expected by investors. Recent bidding rounds, especially after 2016, have warmed up the market. However, exploration pace has slowed down due to these 5 years without bids and the immediate effect of this interruption was the postponement of investments and discoveries. It also hindered the expansion of companies which had stablished in the country, focusing on the consistency of the sector opening process.

In the absence of new opportunities, some companies possibly redirected investments for exploratory alternatives in other countries, weakening the domestic industry. Thus, this lack of a transparent agenda for bidding rounds in Brazil hindered the industry growth. Fortunately, in the first semester of 2017 it was announced a Multi-year planning of bidding rounds, that includes ten new rounds to occur during 2017 until 2019. The ten biddings includes PSA rounds (Pre-salt), concession rounds and even marginal accumulation rounds. This important agenda brings more predictability, and therefore increases reliability and enable the oil companies to better plan their investments in E&P in Brazil

 (ii) Creation of a new regulatory framework for the Pre-salt (subsalt reserves) and strategic areas


When the production sharing agreement was created, the state-owned oil company Petrobras was obliged to be the operator and take at least a 30% stake in all blocks, while other companies including Petrobras could bid on the remaining 70%. This arrangement had enhanced Petrobras’ participation in the Brazilian upstream sector, but did not stimulate much private participation. Such rules were in place during the first PSA round that occurred in 2013, with only once consortium indeed bidding. There are disputes over how efficient this model may be to boost the development of Pre-salt untapped resources.

In May 2017, a decree changed the rules that regulates Petrobras participation in the Pre-salt.  Now the National Energy Policy Council (CNPE) will offer Petrobras the right to choose the auctions that will participate. The State-owned company must express the interest in being the operator of blocks, in the thirty days following the publication of the technical parameters of the auctions, indicating the percentage that desire to have.

After that, CNPE will propose which blocks should be operated by Petrobras, indicating its minimum stake, which must not be lower than 30%. If Petrobras decides not to be the operator, tenders will be opened for the blocks. In this case, Petrobras can still participate in the auctions, in a free competition with the other oil companies. Now the government has more flexibility to promote Pre-salt bidding rounds, without enforcing Petrobras to commit to investments that impair the Company’s investment strategy.

Additionally, other possible challenge for the companies operating Pre-salt fields are the cost recovery mechanism in the production sharing agreements. As this type of contract is new in Brazil and a new entity was also created to manage the PSAs on behalf of the Government, uncertainties arise on the day-to-day activities for all stakeholders involved. If oil companies, e.g., do not manage to recover its recoverable costs in an efficient manner, it can impact materially the return of projects and consequently influence the appetite for the new bids in the Pre-salt.  


Operate in an enviroment with different E&P regimes, such as there is in Brazil, can make the unitization process even more challenging  

When reservoirs or deposits go beyond the ring fencing of an exploratory field, over another area already granted or non-contracted area, the procedure of individualization of production or unitization should be implemented to avoid predatory production. In this process involving different oil companies, for instance, it will be established the participation of each player in the production of the deposit and who will be the operator of the field, which will have its development in a unified manner.

However, there are significant challenges in the cases in which the unitization process involves more than one regulatory regime, such as can occur in Brazil: Concession (tax/royalty), Onerous Assignment and PSA. In such cases, the process tends to be more complex, imposing significant costs to the parties, increasing the cost of the project and delaying the first oil.

Actually, this situation already occurs in Brazil, as there are developing fields in the pre-salt area, whose reservoirs go beyond the ring fencing of the field. In these cases, those extra volumes must be developed under a PSA. In this sense, it is worth mentioning that the second PSA bid round, e.g., that took place in 2017 offered blocks with unitizable deposits, this is, adjacent to fields or prospects whose reservoirs extend beyond the contracted area.

Environmental and social responsibility

The 2010 Gulf of Mexico disaster serves as a grieve reminder of the risks involved in developing ultra-deep offshore Oil & Gas projects

The social, economic and environmental impacts caused by the oil spill at the Gulf of Mexico expose the risk associated with the development of ultra-deep oil and gas reservoirs.  As Brazil embarks in the development of the Pre-Salt, it has a vested interest in drawing from the lessons learned from this tragic event. Companies need to consider not only their revenue margins, but also the set of rules that exist alongside them.

Brazil’s National Petroleum, Natural Gas and Biofuels Agency (ANP) is regarded as having some of the strictest environmental policies in the worldwide. However, none of this prevented the disaster that occurred in 2011 in the Frade field, which is located in the Campos basin. The ANP accounted Chevron as responsible for the errors in the procedures adopted in the field, and the company was ordered to halt all activities, causing millions in losses. These accidents underline the challenges of deep-water drilling and production.

But social responsibility goes well beyond legislation. The largest part of what a company is expected to do is not translated into regulations. It is understood as the ethical standpoint that companies need to take facing their own businesses, how they affect the society and the environment, and what the companies themselves can do to use their profits to revert the negative effects that they may have caused with their operations.

Petrobras, the largest O&G operator in Brazil, considers safety one of its pillars, and is investing largely on training of a high-skilled professional class, in order to minimize the possibility of a spill, and has determined the goal to achieve a “zero-death, zero-spill” mark, being the most important statistic for the company’s Corporate Social Responsibility (CSR) policies.

In line with the goal of reducing environmental impact, companies must go above and beyond the minimum requirements. This means investing in the community, creating jobs, and fostering education. It also means reducing CO2 emissions in its activities as well as finding and developing energy-efficient best practices.

Non-technical risk in the exploration and production 

Non-technical risk (NTR) has been affecting the development of O&G projects in several countries, including Brazil

The O&G industry faces significant non-technical risks (NTRs) worldwide, because of its complex operating environment and multiple stakeholders, which can at times provide conflicting steer. This, in turn, can negatively impact project timeline, costs and value. Within the segments of the O&G industry, NTR can represent a more material threat to the value of upstream projects, as there are higher numbers of factors that can affect exploration and production (E&P) operations. The NTRs can be related to regulatory, public, socio-economic, governmental and environmental matters, all of which could affect projects, delaying their execution and generating cost overruns, thus affecting operations and eroding Net Present Value (NPV).

In Brazil the case with highest highlight refers to delays and difficulties that oil companies are having to obtain the license to explore the blocks acquired in the bid 11 in 2013, from the Brazilian Institute of Environment and Renewable Natural Resources (Ibama). The main consequence is that projects are being delayed and, in some cases, operators are facing the risk of having the licensing process archived, or in the worst case, having to relinquish the blocks to ANP. Thus, it is relevant to evaluate and develop strategies to manage NTR since the bidding round.

Regional geopolitical challenge

Stronger competition for upstream investments in Latin America

The economic crisis and difficulty to finance NOCs are driving the implementation of market-oriented energy policies in LatAm. These changes not only encourage private investment, but also create attractive regulatory and market mechanisms.

Brazil is in a fortunate position concerning the future development of oil reserves and production. However, the geologic potential is necessary, but insufficient to guarantee the social and economic benefits coming from these resources.

Globally speaking, investments in big upstream projects with longer payback are being considered more conservatively, as capital discipline are still being implemented by oil companies, which are also less susceptible to be exposure to long-term risks in the current scenario (IEA, 2018). Ultimately, companies will keep prioritizing projects. In this sense, Petrobras and ANP has been working hardly to reinforce the importance of investments coming from other companies to keep industry dynamics.

The competition for investment in LatAm tends to increase with more pragmatic oil and gas policies implemented by several countries, e.g. Mexico or new frontiers such as Guyana. It is important to stress to that Vaca Muerta in Argentina is being considered the first unconventional play outside North America and is also attracting the majors oil companies interest. Thus, investments in Brazil will be compared with the potential risk and return of alternative options.

This adds both market and political pressure on Brazil to continue its progress in reform, transparency, and potential return on capital invested. It is indispensable to create an attractive market environment, to catch the foreign investment that Brazil needs to achieve and sustain its desired global competitive oil and gas position.

Aging fields

Most of the fields in Brazil are mature and they production have been declining in the last years

The mature fields in Brazil are located both onshore and offshore (conventional or pos-salt), and its declining production curve is drawing the attention of the Government and Petrobras, who operates most of it. The ANP is implementing several actions in order to try to reduce the decline rate or extend the life cycle of these mature fields, such as: reduction of royalties for the exceeding production; extension of production phase (e.g., renewing contract from the round zero);  promoting the use of new recovery technologies; incentivizing the assignment of rights of fields, which operators are not investing enough to maximize recovery factor; and regulating the Reserve Based Lending (RBL), in attempt that allow oil companies to use the remaining reserves as collateral to raise the funds, as this is great challenge in the oil industry. Apart from requesting ANP the extension of older contracts, Petrobras has also making partnerships with other IOCs, such as Statoil, looking for their knowledge in enhancing recovery factor and/or also to fund part of investment needed in these activities.


There is a great amount of production system in Brazil to be decommissioned in the near future, and there is not much experience in the country with this

Even if ANP and the main operator of mature fields in Brazil, i.e., Petrobras, succeed in reducing the decline rate of production of O&G, inevitably fields will deplete and the production system will be removed to attend the legislation. ANP informed that from 2014 until September 2017 there were already 43 request of deactivation of installations and that from 160 offshore platforms in the country 68 (42%) had 25 years or more, 30 (19%) had between 15 and 25 years and 62 (39%) had 15 or less. These figures illustrate the magnitude of challenges that the oil sector in Brazil will face within decommissioning in the near feature.

Additionally, it should be stressed that in Brazil there are at least three governmental organizations sharing responsibility within decommissioning: the navy, the Brazilian Institute of Environment and Renewable Natural Resources (IBAMA) and the sector regulator ANP. This is a new issue in Brazil and IBAMA highlights the following challenges in respect to decommissioning in the O&G sector:

  • Existing environmental liability
  • Lack of specific normalization
  • Exotic bio-invasive species
  • Special waste
  • Disposal of scrap and waste
  • Cost vs. Insufficient Preparation
  • Assimilation of "culture of environment"
  • Environmental recovery / restoration
  • How, what and where to monitor?
  • Responsibilities in mature fields
  • Responsibilities in fields returned

Due to the provisions costs of decommissioning being so high and the level of uncertainties to determine the estimative, Petrobras states in its 2017 financial report that the auditing considered this matter as significate. In 2016 the company had estimated the cost with decommissioning as R$ 33.412 million, but in 2017 it rose to R$ 46.785 million, and part of that was appointed because of anticipation of chronogram of abandonment of some projects. Petrobras in this financial report also underlines that the most significant asset removal obligations involve the removal and disposal of offshore O&G production facilities, and that this cost estimative are complex and involve significant judgment.

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