Waves of regulatory reforms and winds of uncertainties in the Brazilian natural gas industry

Abstract

The natural gas industry in Brazil has undergone three waves of reforms since the late 1990s regarding liberalization and market opening. The gas law approved in 2021 reinforces the unbundling between transport and commercialization of natural gas and guarantees third-party access to essential infrastructure. The new legal framework achieves the vertical separation of upstream and midstream segments but does not reach the downstream segment subject to state regulations. The exit of the incumbent (Petrobras) from the network segments opens space for new entrants, but may remain with a high commercialization share. Vertical and horizontal integration in the distribution segment can compromise this industry’s restructuring. This article identifies three possible scenarios for the evolution of liberalization after the last reform. A successful path will depend on the implementation and enforcement of the new gas law, on adequate economic signals for network and consumption expansion, on harmonization of state regulations, and on the effective opening for the construction of a national gas market. The role of natural gas in Brazil’s energy transition is still an open issue that will affect the industry’s evolution in the coming years.

Keywords

Brazilian natural gas industry network industry restructuring unbundling competition regulatory harmonization

Introduction

In recent decades, different network industries have been restructured in several countries facing a long process of liberalization and market opening, with the separation of non-competitive regulated segments. Since the late 1990s, Brazil has undertaken successive waves of reforms – mainly influenced by European reforms – to liberalize its natural gas industry.

However, the longstanding vertically integrated structure of the market kept it the way it was throughout different waves of reforms. Despite the potential envisaged by different players and governments, there has not been a relevant player with a position to contest Petrobras’ dominance, the former national monopoly company. There are many causes for this, but one of the main entry barriers, related to the presence of a state-owned incumbent with dominance in all the segments of the industry, has not been addressed until recently, in 2019.

As observed in other countries, the 1988 Federal Constitution originally maintained the federal monopoly over different parts of the oil and gas industry – namely exploration and production, imports and exports, oil refining, maritime and pipeline transportation. Also, the Constitution gave the States the competence to explore and regulate pipeline distribution. Until 1995, only the Brazilian Government could perform such activities, directly or through a state-owned company, without constitutional permission to grant licenses to private parties. In 1995, with the first wave of liberal reforms, the Constitutional Amendments No. 5/1995 and No. 9/1995 were approved and legally enabled the entry of private parties.

After the Constitutional Amendments, Brazil passed through three main milestones of regulatory reforms in the natural gas market: (i) the first one in 1997, a continuation of the reforms that led to the Constitutional Amendments, with the enactment of the Petroleum Law; (ii) the second one in 2009, with the approval of a tailored framework for the natural gas industry, the Gas Law; and (iii) the third, more recently, in 2021, with the New Gas Law. The last two reforms, specially the last one, were largely influenced by the reforms made in the European Gas Market, with the three EU Directives.¹ Furthermore, only the third reform addressed deep-routed antitrust concerns, with the execution, in 2019, of a Consent Order between the national antitrust Authority (CADE) and Petrobras.

After the first wave of reform failed to induce openness in the gas industry, the literature emphasized the need to reformulate the regulation of the sector, ensure non-discriminatory access to the transport network and promote changes to encourage infrastructure expansion. While some proposals defended the maintenance of the authorization regime for the exploration of the transport activity (Ana et al., 2009), others supported a change to the concession regime (Mathias & Szklo, 2007). The second wave of reforms started from the consensus that light-handed regulation was not sufficient to deal with the monopolistic presence of Petrobras in the entire industry (Cordeiro et al., 2012); however, it resulted in an overly centralized and complex coordination for access and expansion of the infrastructure (Ferraro & Hallack, 2012).

Despite advances with a first law dedicated to natural gas, crucial aspects for liberalization were left aside in the second reform, especially related to unbundling and limits on verticalization (Cordeiro et al., 2012). These aspects were only deeply addressed after the third wave of reforms (Vazquez et al., 2017; IEA, 2018; Diaz, 2021). The perception that the monopoly of gas distribution and commercialization could develop verticalization strategies resulting in market foreclosure was pointed out since the first wave of reforms (Almeida & Oliveira, 2000). However, the liberalization in the states and the construction of a competitive national market remain a challenge even after the edition of the new legal framework. The partial unbundling in the downstream between transport, distribution and commercialization can make it difficult to open and build a national gas market in Brazil. Despite the three waves of restructuring, Petrobras maintains high participation in gas commercialization, reinforced by the predominance of offshore associated gas production in the national supply.

In parallel, the importance of thermal power demand and the risks associated with its high variability and unpredictability have prompted analyses on the lack of integration between the gas and power sectors and its consequences for the expansion and opening of the gas industry (Oliveira & Marreco, 2006; Gomes, 2014; Campos et al., 2017; Leal et al., 2019). The lack of network capillarity is more identified as a bottleneck for gas industry development than as a symptom of the industry’s boundary conditions and competitiveness. In this sense, proposals for forced expansion of the gas network have thrived in the industry, relying on anchor-consumption of gas-fired thermal plants for baseload generation in regions lacking both gas pipeline infrastructure and significant potential demand. In this context, the waves of reforms face winds of uncertainty regarding the role of natural gas in the Brazilian energy transition.

The objective of this article is to analyze the evolution of legal frameworks after successive waves of reform in the Brazilian gas industry, identifying challenges and risks for the implementation and enforcement of the new gas law for achieving the envisioned liberalization and market opening. To analyze the possible paths of evolution, the paper outlines three possible scenarios for the liberalization process: (i) wrecked; (ii) truncated; and (iii) successful liberalization.

The boundaries between transport, distribution and commercialization of natural gas are subject to recurrent disputes between federal and state regulatory competencies. The possibility of vertical and horizontal integration in downstream, coupled with the resistance of the states to the process of harmonization of state regulations for market opening, guided by federal legislation, can lead to a scenario of truncated liberalization. In this scenario, the opening process can lead to islands of disintegrated markets and asymmetric development among the different regions of the country.

To understand the possible scenarios for the evolution of the Brazilian gas industry, the article is divided into five sections, including this introduction. The second section presents the structure of the gas industry in Brazil; the third analyzes the three waves of reform undertaken; the fourth point outs some of the main risks and challenges faced by the ongoing reform, discussing possible scenarios for the liberalization process; and the fifth makes final comments and policy recommendations.

The Brazilian natural gas industry

The natural gas industry in Brazil is marked by the prevalence of offshore natural gas production associated with oil exploration. The organization of the industry is characterized by the division of federal competence for the upstream and midstream segment and state competence for the downstream segment. Even after the third wave of reforms, commercialization is still subject to regulatory competence disputes. Historically, Petrobras has preserved a monopoly position in the entire gas chain. After the disinvestment process in the network segment (transport and distribution), the company still holds a large stake in the production and gas commercialization. This section provides a historical portrait of the gas industry in Brazil, highlighting the recent changes that accompanied the enactment of the new legal framework.

The Brazilian natural gas sector

Natural gas² accounted for 11.8% of the total domestic energy supply in Brazil in 2020 (287 million tons of oil equivalent), behind oil and its products (33%), sugarcane biomass (19%), and hydropower energy (12.6%). Domestic natural gas production is predominantly offshore and associated with oil, around 85% of the gross production in 2021 (Table 1). The reinjection of natural gas has increased in recent years, mostly in offshore fields in pre-salt oil exploration areas. The pre-salt resources contain significant reserves of associated gas; however, its monetization is still challenging. While the gross national production has doubled in the last decade, the domestic supply that reaches the market has only increased by two-thirds, reaching 51 million cubic meters per day (Mm³/d) in 2021. Proved reserves in 2020 registered 338 billion cubic meters, which results in an 7-year reserve/production ratio (MME/EPE, 2021; MME, 2021).

Table 1.

Evolution of the Brazilian natural gas national balance.

Mm³/d	2010	2011	2012	2013	2014	2015	2016	2017	2018	2019	2020	2021	% 2021	% 21/10
+ National Production	62.9	66.0	70.6	77.2	87.4	96.2	103.8	109.9	111.9	122.4	127.5	133.8	100%	113%
Onshore	16.5	16.8	16.7	20.6	23.3	23.0	23.8	21.5	22.0	22.7	20.5	22.7	17%	37%
Offshore	45.3	49.1	53.9	56.6	64.1	73.3	80.0	88.4	90.0	99.7	107.0	111.1	83%	140%
Associated	47.1	48.6	49.0	51.4	58.6	70.2	78.2	84.8	88.7	99.9	108.1	114.1	85%	142%
Non associated	15.7	17.3	21.6	25.8	28.8	26.1	25.6	25.1	23.3	22.5	19.3	19.7	15%	25%
− Reinjection	12.5	11.1	9.7	10.6	15.7	24.3	30.2	27.6	35.1	43.2	54.7	60.8	45%	385%
Onshore	9.4	7.8	6.8	6.1	7.3	8.4	9.1	8.2	8.4	8.5	6.4	6.2	10%	−34%
Offshore	3.1	3.3	2.9	4.6	8.4	15.9	21.2	19.4	26.7	34.7	48.2	54.6	90%	1668%
− Loss and flare	6.6	4.8	4.0	3.6	4.4	3.8	4.1	3.8	3.7	4.4	3.4	3.4	3%	−49%
− Self-consumption in E & P	9.7	10.2	10.6	10.9	11.5	12.2	12.9	13.4	13.7	15.0	14.6	14.3	11%	47%
− Absorption in processing units	3.6	3.4	3.5	3.6	3.6	3.8	4.2	4.6	4.3	4.5	4.3	3.7	3%	5%
= Domestic supply	30.4	36.5	42.8	48.5	52.2	52.2	52.4	60.5	55.1	55.4	50.5	51.5	38%	69%
+ Import - Bolivia	26.9	26.8	27.5	31.8	32.8	32.0	28.3	24.3	22.1	18.7	17.9	19.9	43%	−26%
+ Import - Aregntina	0.0	0.0	0.0	0.2	0.2	0.5	0.0	0.0	0.0	0.0	0.0	0.2	0%	0%
+ Import - LNG	7.7	1.7	8.5	14.6	19.9	17.9	3.8	5.1	6.9	8.3	8.4	26.2	57%	241%
= Imported supply	34.6	28.5	36.0	46.6	52.9	50.4	32.1	29.4	29.0	27.0	26.3	46.2	100%	34%
− Losses in pipeline and adjustes	3.87	3.4	3.9	3.7	5.8	3.9	4.3	4.3	5.3	5.5	4.7	4.1	4%	7%
= Total supply	61.1	61.6	74.9	91.4	99.3	98.6	80.3	85.6	78.9	76.9	72.1	93.5	100%	53%
− Non-thermal power demand	45.9	51.2	52.0	51.3	52.4	52.7	50.7	51.3	51.2	48.9	46.0	50.7	69%	0%
Industrial segment	35.4	41.0	42.0	41.8	43.0	43.6	40.8	40.8	39.8	37.0	36.1	40.2	69%	0%
− Thermal power demand	15.8	10.4	23.0	40.1	46.8	45.9	29.6	34.3	27.7	29.0	26.1	42.8	31%	171%

Source: Own elaboration based on MME (2021)

The associated gas in the pre-salt fields is rich in liquids (average of 12%) but contains a high share of contaminants. Carbon dioxide can reach up to 80% and must be separated still on the platform to prevent corrosion of the offshore gathering gas pipelines. The exploitation of associated gas offshore implies a high infrastructure cost, and the final investment decision must be taken well in advance in the reservoir development plan. The reinjection generally favors oil recovery and dismisses infrastructure for CO₂ separation and gas gathering, reducing the gas supply to the market. On the other hand, onshore exploration in Brazil, on which there is lower geological knowledge, is still in its infancy (accounting only for 17% of the national production).

The national supply is complemented by imports from Bolivia – through the Bolivia-Brazil gas pipeline (GASBOL) inaugurated in 1999, which has a maximum capacity of 32 MMm³/d – and by three regasification terminals of liquefied natural gas (LNG) – in the states of Ceará (7 MMm³/d), Bahia (20 MMm³/d) and Rio de Janeiro (20 MMm³/d). In Sergipe (21 MMm³/d) and Rio de Janeiro (14 MMm³/d), two other terminals are not yet connected to the gas pipelines, supplying only thermal power plants.

Non-thermal power demand, composed mainly by the industrial sector (80%), has been stagnant at around 50 Mm³/d in the last 10 years. The use of natural gas in vehicles (about 6 MMm³/d) is the second primary non-thermal demand. There is no relevant need for heating in Brazil, thus the residential natural gas consumption through pipelines is small (about 1.4 MMm³/d), restricted to large centers with old pipeline networks initially built to supply manufactured gas. Only about 8% of the 5760 municipalities have a gas pipeline network (BNDES, 2020).

Natural gas can be replaced in all uses, i.e., it does not have a captive market. Therefore, its penetration in the matrix depends on its competitiveness vis-à-vis other substitute energy sources.³ The lack of essential residential demand and the competition from substitute sources for cooking and heating water – mainly LPG, electricity, and firewood – restrict the potential capillarity of the gas pipeline network.

The natural gas demand for thermal power fluctuates depending on the hydropower generation, which is the predominant source of electricity (around 70%). The thermal power demand oscillates around 35 MMm³/d on average in the last 10 years, reaching 55 MMm³/d in critical hydrological periods. The variability of thermal power generation constitutes the primary demand for flexibility in the Brazilian natural gas industry, with a more significant and seasonal generation trend during the dry hydrological period – generally between April and October. There is still no developed large natural gas storage capacity connected to the grid. In turn, the power system counts on huge hydro reservoir capacity (currently equivalent to 4 months of the annual electricity consumption). Importing LNG in the spot market is the primary mechanism to meet the high and unpredictable demand for thermal power generation (Figure 1).

Figure 1.

Evolution of natural gas supply and demand in Brazil. Source: own elaboration based on MME (2021).

The gas pipeline network is mainly located on the country’s coast. There are three leading transmission system operators (TSOs): TBG in the GASBOL; NTS in the Southeast of the country; and TAG in the Southeast, Northeast, and North regions (Urucu-Manaus Gas Pipeline) (Figure 2). The gas pipeline network increased from 4000 km (km) in 1999 to 9400 km in 2011, remaining stagnant. The distribution network jumped from 4000 km in 1999 to 38.6 thousand km in 2020, with an average annual growth rate of 17% in the first 10 years and 7% in the last ten.

Figure 2.

Natural gas transport network in Brazil. Source: Adapted from Petrobras.

The split of the regulation between federal and state competencies

The 1988 Federal Constitution of Brazil (art. 25) establishes the states’ competence to explore local distribution network business (“local piped gas services”), directly or through concession.⁴ The upstream and midstream segments of the gas industry – exploration and production, imports and exports, underground storage, oil refining, maritime and pipeline transportation – are under the federal jurisdiction of the Union. Commercialization and tanking storage are also regulated by the federal government, but under a less interventive regime. The National Agency for Petroleum, Natural Gas, and Biofuels (ANP) is responsible for the federal regulation. In the states, the regulation is undertaken by the state’s executive government or by regulatory agencies when they exist (generally multi-sectorial). The federal Administrative Council for Economic Defense (CADE) is responsible for analyzing and validating mergers and acquisitions and investigating and prosecuting infringements of free competition.

The constitutional boundary of “local piped gas services” raises recurrent disputes between state and federal regulatory jurisdictions. The states generally act on all activity related to pipeline distribution, setting it up as a state legal monopoly – through state laws, concession contracts, and resolutions of regulatory agencies. In practice, the sphere of local services is not limited to the regulation of distribution activity (natural monopoly). State regulations generally encompass competitive activities such as the commercialization of piped natural gas and even the distribution and commercialization of LNG and CNG, which are under federal competence. Over time, the reforms implemented at the national level and the ANP regulation turned to delimit more clearly the regulatory powers of the Union and, more recently, to harmonize the states’ regulations.⁵

Table 2 presents a picture of gas distribution in Brazil. The Southeast region concentrates 63% of the non-thermal demand of local distribution companies (LDC) in the country, followed by the Northeast (21%) and the South (13%) regions. Only Rio de Janeiro and São Paulo have concessions controlled by private capital⁶, supplying 52% of the national non-thermal power demand. Comgas alone, which covers the metropolitan area of São Paulo, accounts for 30%. The state of Rio de Janeiro established two concession areas (both operated by Naturgy), and São Paulo set three distinct areas. All other distribution concessions coincide with the entire area of the states. Only three states do not have a distribution company, while most LDC in the North and Midwest regions are non-operating companies. Most states in the Northeast region – where Bahia and Pernambuco account for 80% of the consumption – have insignificant demand and network infrastructure. Besides, the Covid-19 pandemic reduced 11% of the LDC’s non-thermal demand in 2020.

Table 2.

Natural gas local distribution companies in Brazil.

Local distribution companies (LDCs)	State	Shareholding structure (%)			Contract extension (years)	Network customers	Network extension	Annual demand, excluding thermal power segment (Mm3/d)
Local distribution companies (LDCs)	State	State	Gaspetro	Private	Contract extension (years)	Network customers	Network extension	2015	2016	2017	2018	2019	2020	2021	Average	%
South region						97.552	3.045	5.1	4.8	4.8	5.2	5.5	4.7	4.8	5.0	12.9%
Sulgás	RS	—	49	51	1993–2043 (50)	43.631	1.095	1.9	1.9	1.8	2.1	2.2	2.0	1.7	2.0	5.0%
SCGás	SC	51	23	26	1994–2044 (50)	12.069	1.138	1.7	1.7	1.8	1.4	2.0	1.8	2.2	1.9	4.9%
Compagás	PR	51	25	25	1494–2024 (30)	42.232	812	1.4	1.3	1.2	1.2	1.4	0.9	0.9	1.2	3.0%
Southeast region						3.134.794	25.354	25.1	23.4	24.8	25.5	25.1	22.7	26.0	24.6	63.7%
Comgás	SP	—	—	100	1999–2049 (30)^a	1.905.455	15.000	11.7	11.4	11.8	12.4	12.4	11.6	13.3	12.1	31.2%
Naturgy SP	SP	—	—	100	2000–2030 (30)	82.839	1.664	1.1	1.1	1.1	1.1	1.1	0.8	0.9	1.0	2.7%
Gás brasiliano	SP	—	100	—	1999–2029 (30)	22.282	1.034	0.8	0.7	0.7	0.7	0.7	0.6	0.9	0.7	1.9%
Naturgy RJ (CEG)	RJ	—	—	100	1997–2027 (30)	954.631	4.684	4.1	4.1	4.3	4.5	4.5	3.9	4.3	4.2	10.9%
Naturgy RJ (CEG rio)	RJ	—	26	74	1997–2027 (30)	78.770	1.341	2.4	2.1	2.5	2.3	2.4	2.2	2.4	2.3	6.0%
ES gás	ES	51	—	49	2020–2045 (25)	48.516	447	0.4	1.7	1.7	1.8	1.8	1.3	1.6	1.8	4.5%
Gasmig	MG	100	—	—	1093–2053 (30)^a	42.301	1.184	2.6	2.3	2.6	2.6	2.3	2.2	2.6	2.5	6.4%
Midwest region						8.305	318	0.2	0.3	0.4	0.6	0.9	0.6	0.6	0.5	1.4%
MSGás	MS	51	49	—	1998–2028 (30)	8.305	318	0.2	0.3	0.4	0.6	0.9	0.6	0.5	0.5	1.3%
Goiasgás	GO	51	20	50	2001–2030 (30)	—	—	0.0	0.0	0.0	0.0	0.0	0.0	0.0	0.0	0.0%
Cebgás	DF	51	21	28	2001–2030 (30)	—	—	0.0	0.0	0.0	0.0	0.0	0.0	0.0	0.0	0.0
MTGás	MT	—	—	—
Northeast region						215.295	3.594	8.1	7.9	8.1	8.8	8.7	8.0	9.3	8.4	21.7%
Bahiagás	BA	51	25	25	1991–2041 (50)	52.044	905	3.6	3.4	3.6	3.8	3.7	3.4	3.6	3.6	9.2%
Copergás	PE	51	25	25	1992–2042 (50)	31.705	754	2.6	2.7	2.6	3.0	3.1	3.1	2.9	2.8	7.3%
Algás	AL	51	25	25	1993–2043 (50)	47.519	498	0.6	0.6	0.6	0.6	0.5	0.5	0.6	0.6	1.5%
Cegás	CE	51	25	25	1993–2043 (50)	14.648	472	0.5	0.4	0.5	0.5	0.6	0.5	0.5	0.5	1.3%
Potigás	RN	51	49	—	1994–2044 (50)	24.386	407	0.3	0.3	0.3	0.3	0.3	0.2	0.2	0.3	0.7%
PBGás	PB	51	25	25	1994–2044 (50)	16.172	326	0.3	0.3	0.3	0.3	0.2	0.2	0.2	0.3	0.6%
Sergás	SE	51	25	25	1993–2043 (50)	25.821	232	0.3	0.3	0.3	0.2	0.3	0.2	1.2	0.4	1.0%
Gasmar	MA	51	21	28	2002–2031 (30)	—	—	0.0	0.0	0.0	0.0	0.0	0.0	0.0	0.0	0.0%
Gaspisa	PI	25	37	37	2002–2031 (30)	—	—	0.0	0.0	0.0	0.0	0.0	0.0	0.0	0.0	0.0%
—	TO
North region						298	119	0.1	0.1	0.1	0.1	0.1	0.1	0.2	0.1	0.3%
Cigás	AM	51	—	49	2002–2040 (30)	298	119	01	0.1	0.1	0.1	0.1	0.1	0.2	0.1	0.3%
RonGás	RO	17	41	41
Gás do pará	PA
Gasap	AP	25	37	37
—	RR
—	AC
Total						3.456.624	33.430	38.6	36.6	38.2	40.2	40.4	36.1	40.8	38.7

^aContract already extended.

Source: Own elaboration based on Vazquez et al. (2017), MME (2021), and BNDES (2020).

Most concessions follow the same model of the shareholding structure with most of the capital held by the state and the other half divided between Gaspetro (a Petrobras subsidiary) and a private entity (usually Mitsui).⁷ These contracts predate the General Concessions Law (No. 8987/1995), with terms ranging from 30 to 50 years, usually extendable. They also set a fixed return rate of 20% per year that remunerates the cost of capital (regulatory asset base) and operating costs. This rate is high and detached from the current macroeconomic and sectorial reality.⁸ The tariff calculation also has a 20% reduction factor for the projected market volume, increasing the volumetric tariff level. Also, these contracts do not set quality or expansion targets. The consequence thereof is the disproportionate increase of distribution tariffs for the served consumers and the loss of competitiveness of piped natural gas compared to its commercialization alternatives (LNG and CNG) and substitute energy sources, making access far away to unserved consumers.⁹

Contracts derived from bidding processes (privatization) in the late nineties – concessions in Rio de Janeiro and São Paulo – establish a price cap regulation with periodic tariff revisions for setting regulatory asset base, efficient operation costs, rate of return (WACC), and a X Factor for sharing efficiency during tariff cycles.¹⁰ Some states have already revised their concession contracts in this direction, such as Minas Gerais and Espírito Santo. Petrobras' disinvestment in the distribution segment (with the total sale of its equity stake in Gaspetro) has not induced a revision of the LDC’s contracts.

Figure 3 shows the average tariff for end-consumers by segment in Brazil. The gas price for industry (consumption of 20 thousand m3/d) reaches US$ 15.6/MMBtu on average with taxes in December 2021, while the average for residential consumers reaches US$ 32.2/MMBtu. By way of comparison, the average gas price (with taxes) for non-household consumers reached US$ 17.4/MMBtu in the European Union in the second half of 2021; while the average price for household consumers reached US$ 27.5/MMBtu in the period, which was marked by historic price peaks in the international gas hubs.¹¹ On average, the price of natural gas accounts for 44% of the industrial consumer tariff, transport for 15%, distribution 17%, and taxes 24% in Brazil (EPE, 2020).

Figure 3.

Average consumer-end tariff in Brazil (December 2021). Source: Own elaboration based on MME (2021).

The monopolistic position of petrobras in the industry

Despite the sector’s opening implemented in the nineties, Petrobras remains a dominant agent in the oil and gas industry. In 2020, Petrobras accounted for about 75% of the national production of natural gas (127 Mm3/d) and oil in Brazil (2.9 million barrels/day), followed by Shell (about 12%) (ANP, 2021).¹²

In the natural gas industry, Petrobras has completely dominated the entire chain from production to consumption as it (i) has shareholdings in all gathering gas pipelines, processing units, and in the three LNG regasification terminals connected to the grid; (ii) had shareholdings in the entire gas pipeline network until recently, but currently only holds an equity share in TBG (51%) after the divestment of TAG and NTS grid; (iii) is the main carrier in the gas pipelines transport system and the gas trader in the country; (iv) has a shareholdings in 19 of the 27 existing LDC through its subsidiary, Gaspetro, which is in the process of disinvestment for Compass, awaiting approval by CADE; and (v) is also a relevant gas consumer through its thermal power plants (over 6 GW installed capacity), refineries and fertilizer plants.

The de facto monopoly of Petrobras enabled the development of the initial supply chain infrastructure by assuming risks outside the nature of the oil and gas industry, arising from the unpredictable and variable demand of thermal power generation in the country. This integrated portfolio helped guarantee supply and provided flexibility to manage the variable and unexpected thermal power demand.¹³ However, the monopoly in all chain segments – encompassing competitive and regulated activities – neutralized the contestability and inhibited potential gains from the industry opening to competition.

Petrobras’ leading role in the sector reflects the difficulties inherent in partial liberalization processes of network industries.¹⁴ In this context, the verticalization in the entire chain constitutes a structural entry barrier that is difficult to transpose in practice. The successive waves of regulatory, legal, and institutional reforms in the industry sought to reduce the market power of the incumbent dominant agent, impose vertical separation, and build a new competitive market structure (IEA, 2018).

Waves of reforms in the Brazilian natural gas industry

The three waves of reform in the natural gas industry have progressed towards market opening and liberalization, influenced mainly by European directives. The first wave of reform was engendered by the opening of upstream and the end of the Petrobras monopoly, with amendments to the Federal Constitution in 1995 and the enactment of the Petroleum Law in 1997. The particularities of natural gas were not addressed by this law, which led to the issue of a specific law in 2009, focused mainly on midstream aspects. After this second wave of reforms, Petrobras remained the dominant player in the entire chain, the transport network remained stagnant and access barriers to essential infrastructure were not reduced, prompting a third wave of reforms, which was accompanied by the repositioning of Petrobras in the network segment.

First wave: The petroleum Law (1997)

The Federal Constitution establishes the monopoly of the Union for almost all activities in the oil and gas industry, including exploration and production, import and export, refining, and transport. Petrobras exclusively exercised the legal monopoly of the sector until 1995 – except oil products retail – when Constitutional Amendment No. 9 revised Article No. 177 of the Constitution to allow the exploration of activities by private companies. In the same year, Constitutional Amendment No. 5 changed Article No. 25 of the Constitution to allow states to grant the concession of local piped gas services to private companies. The opening took place in the context of liberalizing reforms in several industries, revisiting the state’s role in the economy, and attracting private capital in productive and infrastructure sectors.

In this context, the Petroleum Law (No. 9478/1997) defined the rules for the oil and gas sector, establishing the concession for the exploration and production of resources preceded by a bidding process, as well as the definition of royalties and government participation in oil revenues and others measures. The Law established the regulatory agency – the National Petroleum Agency (ANP), symptomatically still without natural gas in its name – and the National Energy Policy Council (CNPE), chaired by the Minister of Mines and Energy, to define national policies and guidelines for the energy sector.

According to the Petroleum Law, the Union must preserve the shareholding control of Petrobras, allowing the company to set up subsidiaries (without restrictions on capital structure) and associations with other companies in consortiums. The Law also established the legal unbundling of transport activity, exclusively for Petrobras, determining the constitution of a new subsidiary for the ownership and operation of assets for the transport of oil, natural gas, and oil products. Consequently, Petrobras created Transpetro in 1998 and incorporated several gas pipeline subsidiaries into Transportadora Associada de Gás (TAG) over time.

The Petroleum Law treated natural gas as an additional by-product of oil without adequately considering the particularities of its network industry (Cordeiro et al., 2012). The first legal framework did not encompass issues of the midstream and downstream segments, leaving gaps and gray areas to be regulated by the new regulatory agency.

The development of natural gas supply and demand in Brazil only occurred after the inauguration of the Bolivia-Brazil gas pipeline (GASBOL) in 1999. Until then, production was on a large scale reinjected or flared, with its use restricted to Petrobras industrial units. The greater participation of players in the oil and gas industry after the opening of upstream segment and the gradual insertion of natural gas in the energy matrix pressured the need for a specific legal framework to address the particularities of the natural gas industry.

Second wave: The gas law (2009)

The first Gas Law (No. 11,909/2009) resulted from more than 4 years of discussions in the National Congress among various stakeholders. Its regulatory decree also took more than a year to be approved (No. 7382/2010). The first legal framework dedicated to natural gas focused on the midstream segment – processing, transport, storage, liquefaction, regasification, import, and commercialization – including specific downstream aspects. Exploration and production activities (upstream) remained under the legal framework of the Petroleum Law, while downstream segment remained under the competence and responsibility of the states.

The Law sought to encourage the entry of new players in the industry by expanding transport on a competitive basis and ensuring third-party access to the gas pipelines. The Law instituted a complex regulatory process to grant the concession for the construction and operation of new gas pipelines, structuring the market’s architecture on centralized planning and coordination. Free access was subject to an initial period of exclusivity for initial carriers (limited to 10 years), providing incentives to explore new markets without the competition of free riders. Previously, the construction of gas pipelines was granted through authorizations.¹⁵

After the Law, granting new pipelines started to occur under the concession regime through a bidding process preceded by an open season for expression of interest by carriers for the dimension of the minimum transport capacity. The open season also applied to the available (not contracted) or idle (contracted but not used) capacity in existing pipelines and their expansions.¹⁶

The Gas Law reinforced the role of the state in the sector, expanding the responsibilities of the Ministry of Mines and Energy (MME), the regulatory agency (ANP), and the planning agency (Energy Research Company – EPE) to coordinate the planning and expansion of the transport network. The EPE should prepare studies for the development of the gas pipeline network considering the investment plans of the TSOs, market information, and MME guidelines. Based on these studies, the MME should publish a 10-year plan for expanding the transport network (PEMAT) with an annual review. In turn, ANP became responsible for ensuring the open season and the entire bidding process for granting new transport gas pipelines. ANP was also responsible for regulating free access, defining transport tariffs, and ensuring transparency and publicity regarding the availability of gas pipeline capacity to all interested parties.

In addition to the transport service in a firm capacity modality, the Law defines the offer of interruptible (from idle capacity) and extraordinary services (from available capacity not yet contracted in the firm modality). The bidding process determines the gas pipeline transportation tariff. In contrast, the existing gas pipeline tariffs with authorization grants remained freely negotiated between the contracting parties subject to ANP approval.

During the validity of the first Gas Law, MME published only one edition of PEMAT in 2014. The 10-year plan identified nine gas pipelines for expansion, totaling about 4.1 thousand kilometers in length (MME/EPE, 2014). However, it indicated only an eleven-km gas pipeline for tender, proposed by Petrobras, but the auction did not happen. The inability of the new centralized mechanism to mitigate risks and encourage network expansion was evident (Ferraro & Hallack, 2012). The new wave of improvements replaced the PEMAT and its determinative planning with an indicative plan for gas pipelines elaborated by EPE.

The Gas Law sought the unbundling between distribution and commercialization, allowing LDC’s commercial bypass for eligible consumers. For this purpose, the Law instituted the eligible (free) consumer, the self-producer (a producing agent that uses part of the gas in its facilities), and the self-importer (an importing agent that uses part of the gas in its facilities). The states must incorporate these new consumers segments in their legal-regulatory frameworks, defining the minimum limits for the eligibility of these agents.

The natural gas commercialization by these eligible agents does not exempt the payment of the local company’s distribution margin, even if the consumer does not effectively use the distribution network. Therefore, the distribution segment in Brazil exercises a legal monopoly over gas pipeline consumption in the states. The Gas Law allowed the construction of gas pipelines for dedicated use and specific interest when the LDC refuse to invest. In this case, LDC operates the asset receiving a tariff based on operating and maintenance costs established by the state’s regulatory agency, including the asset in the concession’s regulatory asset base. In other words, the Law guarantees the investment to be made regardless of the availability or interest of the local distributor but does not allow the physical bypass of the distribution network.

Third wave: The new gas Law (2021)

To understand the contours of the new natural gas legal framework and the improvements achieved by the third wave of reforms, it is first necessary to go through, chronologically, the political and regulatory context that generated the legal changes, which are presented below.

Antecedents

The evolution of the regulatory framework of the natural gas industry in Brazil advanced towards encouraging the entry of new agents; however, the competition did not materialize in practice. In 2016, the “Gas to Grow” initiative structures new liberalization efforts, envisioning a profound reformulation: (i) infra-legal improvements; (ii) repositioning of Petrobras in the chain segments; (iii) greater emphasis and articulation in antitrust regulation by CADE; and (iv) a new legal framework. The infra-legal advances resulted from the Government articulation. At first, the improvements enabled greater harmonization between gas and power sectors, which favored the competitive contracting of thermal power plants in the energy auctions in the second half of the last decade.¹⁷

On the other hand, Petrobras’ repositioning first started from its own initiative, facing the need for financial and strategic business restructuring (Almeida et al., 2015). Numerous factors contributed to the financial disruption of Petrobras in the mid-2010s, with emphasis on the (i) sharp drop in oil prices as of 2014; (ii) misalignment of domestic prices of oil products vis-à-vis international prices, with substantial losses during an initial period of high investments in pre-salt resources¹⁸; and (iii) investigations of corruption schemes within the company with political involvement, culminating in the “Lava-Jato” operation. To overcome the crisis, Petrobras reorients its oil and gas industry operations towards greater leverage in activities with better risk-return relation – especially the exploration of the pre-salt reserves – and the asset divestment to reduce the growing debt. In this context, the reduction of Petrobras’ participation in the gas industry was identified as strategic and quick to implement, attracting private capital in the divestment of brownfield natural gas transport and distribution assets – NTS, TAG, and Gaspetro. The brownfield assets backed by long-term agreements primarily influenced the capital attraction for Petrobras’ divestment in the segment.

Continuing the infra-legal improvements, Decree No. 9616/2018 amended the Gas Law Decree (No. 7382/2010) to (i) unlock studies for the expansion of the national gas pipeline network; (ii) indicate the implementation of the Entry-Exit model to contract transport capacity; and (iii) determine that ANP should establish guidelines for third-party access to essential infrastructure (gathering pipelines, processing units, and LNG terminals) and authorize and regulate storage activity. In 2019, EPE published indicative planning for gathering and transport gas pipelines and processing units.

The new federal government reinforced the reform movement around the “New Gas Market” initiative, resuming the articulation for the approval of the new Gas Law under discussion in the National Congress.

In June 2019, Resolution No. 16 of the National Energy Policy Council (CNPE) established guidelines to promote competition in the natural gas market. Among the measures, the CNPE guided the (i) promotion of negotiated access to essential infrastructure; (ii) independence of TSOs; (iii) unbundling between commercialization and gas distribution; (iv) transparency of commodity contracts to supply the LDC’s regulated captive market; (v) promotion of gas release programs with commercialization in the market; and (vi) voluntary adoption of best regulatory practices in the states’ regulations.

The CNPE also defined for the dominant position agent (Petrobras) the (i) total divestment of shareholdings in the network companies (transport and distribution); (ii) definition of gas demands at specific points of entry and exit of the transportation system, enabling the offer of additional transportation services in the remaining capacity; (iii) offer of duly remunerated flexibility and network balancing services, ensuring the security of supply during the transition period; (iv) making information available for third parties access to its essential facilities; and (v) carrying out a gas release program through auctions to promote competition in commercialization.

The CNPE guideline also recommends that the MME, ANP, EPE should work together to support capacity building for state regulatory agencies. For the harmonization of state regulations, the CNPE guidelines indicate structural measures with emphasis on the (i) institution of an autonomous regulatory agency; (ii) privatization of LDC; (iii) incorporation of the eligible consumers in the states’ regulations; (iv) unbundling of the commercialization and distribution activities; (v) transparency of commodity contracts of the LDC’s captive market and bidding process for commodity purchasing; and (vi) establishment of a transparent tariff methodology with incentives for efficiency and grid investments, with a tariff structure based on the Beneficiary Pays Principle.

In July 2019, CADE approved the Term of Cession of Conduct (TCC) related to Petrobras’ performance in the gas industry. Among the agreed terms with Petrobras, the following stand out: (i) negotiation of third-party access to natural gas gathering pipelines and processing units; (ii) reduction of third parties natural gas purchase by Petrobras; (iii) definition of excess capacity in the transport pipelines, indicating their demands for each entry and exit point, eliminating Petrobras’ flexibilities and contractual congestion; and (iv) complete divestment in network assets (transport and distribution) by the end of 2021.

The new gas law

Approved in 2021, the new Gas Law (No. 14,134/2021) establishes more precise contours among natural gas chain segments, ensuring free access to essential facilities and defining legal unbundling between transport and competitive activities. The Law prohibits any shareholdings relationship between TSOs and companies operating in competitive segments. Existing TSOs in operation must obtain a certification of independence, attested and regulated by ANP, within 3 years of the law or 2 years of the regulatory agency’s regulation approval.

The Law reinstituted the authorization regime for the construction or expansion of gas pipelines, preceded by an open season, under the terms of ANP regulation, to estimate the effective demand for transport capacity. The authorization regime potentially simplifies the regulatory process for network expansion. The Law revoked the complex regulatory procedures coordinated and centralized by the government through PEMAT, established in the previous legal framework. However, the authorization for a new gas pipeline must have a prior contest period that allows other TSOs to propose an alternative project for the same purpose. ANP must regulate the public selection process in choosing the most profitable project in technical-economic terms if there is an alternative. ANP also has the prerogative to undertake a public selection process to identify TSOs interested in a specific network expansion. The existing TSO has pre-emptive rights to expand its grid under the same conditions as the best proposal.

The Law expanded ANP’s competence to classify transport gas pipelines subject to technical characteristics. Should be classified as transport pipelines: (i) interstate pipelines; (ii) import and export pipelines; (iii) those connecting transport pipelines to LNG terminals, processing units, and storage facilities; and (iv) pipelines whose technical characteristics in terms of diameter, pressure and extension exceed limits of ANP regulation. Existing pipelines remain with their current classification. For the first time, the legal framework allowed the definition of technical parameters for classifying gas pipelines, clarifying the boundaries between transport and distribution networks.

Following the national energy policy guidelines, transport capacity must be contracted under the Entry-Exit model, permitting independent capacity commercialization to inject or withdraw gas from the network. ANP must determine the maximum allowed revenue for the transport activity after a public hearing, defining criteria for readjustment and periodic and extraordinary revisions. Transport tariffs are proposed by the TSOs and approved by ANP.

All activities granted by authorization are at the entrepreneur’s expense and risk without constituting a public service provision. The Union does not guarantee the maximum revenue; thus, entrepreneurs assume the demand risk for investment recovery without assets’ reversal or indemnification.

TSOs in the same market area must constitute a market operator responsible for offering standardized transport services, allocating capacity, ensuring grid balancing, defining common network codes, and elaborating a development grid plan for supply guarantee in a 10-year horizon. It is allowed to contract storage services, access to LNG terminals, among other resources for grid balancing. On the other hand, carriers must set up a consumer council to monitor operational and investment performances in the transport network.

ANP must ensure third-party access to gas pipelines, monitor contractual congestion, discipline the commercialization of capacity, and promote capacity release programs subject to its regulation. ANP may establish an exclusivity period with exemption from free access to new infrastructures. However, unlike the previous law, this exclusivity period is no longer mandatory.

The Law establishes the negotiated access to essential infrastructure – gathering gas pipelines, processing units, and LNG regasification terminals. Underground storage of natural gas is also subject to authorization by ANP and to third-party access after any eventual initial period of exclusivity defined by ANP.

The Law preserves federal jurisdiction for the commercialization of LNG and CNG. It also replicates the provision that allows eligible consumers, self-producers, and self-importers to build gas pipelines for specific interest and dedicated use if LDC does not serve them.

Commercialization is a federal competence subject to authorization and regulation by ANP, except for LDC’s captive markets. The regulatory agency must establish the minimum content of standardized contracts, prohibiting anti-competitive clauses. ANP must also ensure the competitive environment of the gas market, providing gas and capacity release programs (through regulated auctions) for transport, gathering gas pipelines, and processing units. ANP can also restrict the gas trade between producers in production areas to promote competition and supply diversity.

The Law revokes a legal provision that prevented shareholdings of electricity distribution companies in the LDC’s capital structure. By removing undue barriers between power and gas distribution infrastructure operations, the new Law allows synergies from horizontal integration as it occurs in other countries.

Legacy transport capacity contracts must comply with the new Law’s rules within 5 years or 3 years after the specific ANP regulation. However, the law guarantees the revenue provided for the contracts in force, allowing tariff compensation in the following revisions for proven losses. The Union must liaise with the states to transpose its guidelines, harmonize, and improve state regulations.

Winds of uncertainty – challenges and prospects for liberalization

The prospect for liberalization and market opening in Brazil’s gas industry after the latest wave of reform is promising. Petrobras’ divestment in the network segment and the instruments for third party-access to essential infrastructure may favor the entry of new players. However, the road to successful liberalization is challenging, facing obstacles related mainly to the level of openness in the downstream, subject to different states regulations. The boundaries between gas transport, distribution and gas commercialization are subject to recurrent disputes, reinforced by the possibility of vertical and horizontal integration in the downstream segment. The definition of possible scenarios for the evolution of the industry favors the understanding of the challenges and uncertainties to be faced in the coming years.

Possible scenarios for liberalization

From the perspective of the three waves of reform in the Brazilian gas industry and recent advances, one can envision three possible scenarios of evolution for the liberalization and market opening process: (i) wrecked; (ii) truncated; or (iii) successful liberalization. (i)

Scenario of Wrecked Liberalization: the exit of Petrobras in the transport and distribution segments and the enactment of the new gas law at the federal level could indicate irreversible changes in the status quo of the natural gas industry, in terms of concentration, openness and dynamism. However, the transposition of legal frameworks is not automatic and may face challenges for its implementation and enforcement. In this scenario, despite the current changes, the latest wave of reform does not produce concrete effects for the liberalization and construction of a national gas market. In this context, Petrobras remains the main agent in the commercialization and the LDC continue to commercialize gas to the entire universe of distribution consumers, with little or no migration of eligible consumers to the free market. State regulations remain stagnant and disharmonized, with no updating of legacy LDC concession contracts. Expansion of the integrated transport grid remains marginal, while the distribution grid only expands in states with existing grids. The non-thermal market remains with little or no growth.

(ii)

Scenario of Truncated Liberalization: in this scenario, the new regulatory framework induces marginal and heterogeneous advances in terms of competitiveness, openness and dynamism. Islands of non-integrated and asymmetric state markets do not allow the expected gains from national opening with harmonized rules. Petrobras’ participation in commercialization is reduced, with a greater supply diversity. LDC continue to commercialize gas to all or most of the distribution consumers, with little or no migration of eligible consumers to the free market. New state legal frameworks for natural gas conflict with federal competencies established by the federal New Gas Law of 2021, overlapping distribution (“local piped gas services”) with the transport and commercialization activities. State regulations remain stagnant and disharmonized, with marginal updating of legacy LDC concession contracts. While the expansion of the transport network remains marginal or nonexistent, the distribution grid expands in more regions and at a greater intensity, incorporating part of the network that should integrate the transport grid. The horizontal and vertical concentration within the distribution reinforces the disconnection of regions and the lack of harmonization of state regulations. The non-thermal market may expand at a low growth rate and be locally concentrated, subject to the conditions of local LDC integration. Development tends to be asymmetric, widening the current discrepancy between regions which already have access to natural gas and regions with no non-thermal consumption.

(iii)

Scenario of Successful Liberalization: in this scenario, the new regulatory framework produces significant advances in the opening and construction of a national gas market. The implementation of the federal law guarantees the separation between transport, distribution, and commercialization segments, enabling a national gas market with increasing liquidity. Harmonization of state regulations is promoted with capacity building of regulatory agencies and updating of legacy LDC concession contracts. Conflicts between the new state legal frameworks and the federal New Gas Law of 2021 are overcome, guaranteeing federal competence for the regulation of transport and commercialization. Petrobras’ market share in commercialization is reduced, with greater diversity of supply, while LDC gradually reduces its participation in commercialization to eligible consumers for free market. The national gas market contributes to efficient economic signals for the expansion of transport and distribution infrastructure, connecting different sources of supply. The network expansion is subject to the competitiveness of natural gas in the new markets, resuming the expansion of the integrated transport grid. The current asymmetry between regions is gradually reduced, supplying new markets currently not yet served.

The trajectory of the liberalization process in Brazil’s natural gas industry will follow one of the three scenarios described above over the next few years, depending on the implementation and enforcement of the new regulatory framework. The existing conflicts between the spheres of gas transport, distribution and commercialization in Brazil produce forces that move the industry away from the successful liberalization path. Recent changes in the states’ legal frameworks and in the shareholding composition in distribution reinforce the possibility of islands of asymmetric non-integrated markets, without the unbundling of distribution and commercialization activities. In other words, the current trends point to a scenario of truncated liberalization. The path to successful liberalization will increasingly depend on the active articulation of federal regulations, the enforcement of the new gas law and constant action by the antitrust authorities. From this framework, the next section discusses in more detail the challenges of restructuring.

Parallel to the liberalization scenarios, there is the possibility of forced expansion of the transport network linked to the contracting of inflexible gas-fired thermal plants for baseload generation, mostly located in regions without gas infrastructure. This possibility may negatively impact the liberalization scenarios outlined above. Despite the recent trend towards an increased share of gas in power generation and capacity expansion, the energy transition makes the role of natural gas in Brazil’s renewable electricity matrix uncertain, as will be discussed below.

Challenges of industry restructuring

In the United States, the structural unbundling between the production, transport, and local distribution of natural gas occurred in the 1930s. However, the functional unbundling between transport and the commodity’s commercialization of natural gas only occurred after the introduction of regulated third-party access to transport pipelines in the 1980s and the institution of physical hubs for commercialization in the 1990s, allowing the emergence of a competitive natural gas market (Makholm, 2011; OECD, 2000).¹⁹

In the European Union, the liberalization of the gas industry started from the prevalence of national verticalized monopoly companies. The successive waves of reform sought the vertical separation but allowed different network independence models. The construction of a European internal market still faces the challenges of harmonizing national regulations in the process of transposing common directives.

The waves of reforms in the natural gas industry in Brazil advanced towards the neutrality of the transport system through the unbundling between transport and production/commercialization activities, fostering entry and infrastructure expansion towards the successful liberalization scenario. Petrobras’ disinvestment in the transport gas pipelines contributes to the vertical separation, while the new legal framework expands the federal regulatory agency’s competencies to classify transport pipelines. Changing the grant terms (from concession to authorization) and simplifying the regulatory process for transport grid expansion can favor new investments in the system. However, the effective network development depends on economic fundamentals for the competitive insertion of natural gas.

The new Gas Law does not allow shareholdings of new TSOs in competitive activities, determining the certification of independence for existing TSOs by ANP. On the other hand, LDC’s shareholdings in competitive activities are allowed, as clarified by the new law’s decree (No.10,712/2021).²⁰ Ultimately, the network neutrality in the already improved regulation is partial, facing the limits of the fragmented regulatory competence between the Union and the states.

The ANP’s draft resolution (not yet approved) for the certification of existing TSOs’ independence does not include the ITO (Independent Transmission Operator) model, which allows the asset operation by the owners even when they hold shareholdings in the competitive segment. The ITO model requires more robust regulatory and governance measures to ensure grid neutrality.²¹ The primary motivation for not contemplating it is to take advantage of Petrobras’ complete exit from transport to migrate to a more restrictive and less costly regulatory neutrality model. However, the disposal of the ITO model can reduce the range of agents willing and able to act in the gas transport system. In a country that still envisions a gas market development, the trade-off between strict independence and capital attraction must be well balanced to not compromise potential network expansion.

The unbundling between distribution and commercialization services is partial in Brazil. Direct gas commercialization by eligible consumers (mainly industrials) is not mandatory, which creates little pressure for market liberalization. LDC also have the exclusive right to supply through gas pipelines in their concession areas without allowing physical bypass for large consumers. Non-thermal natural gas consumption concentrates in the industry segment and the southeast region. There is low potential to expand the network’s capillarity and the universe of supplied consumers. The prohibition of physical by-pass socializes the network cost due to the greater volume distributed, which can lower tariff for existing and potential small consumers but imposes inefficient cross-subsidies.²²

Despite Petrobras’ divestments in the network segment, the company will probably retain a majority share in the production and commercialization of natural gas in the next decade. The prevalence of offshore and oil-associated production increases the degree of concentration of gas supply. Low onshore exploration reduces the market contest of domestic supply, raising the relevance of LNG imports for increasing competition. In this context, Petrobras’ majority share in the commercialization will likely remain in the coming years, despite the industry’s restructuring and market opening in progress.

There is also a risk of market foreclosure due to partial unbundling in the distribution segment, i.e., the possibility that vertical and horizontal integration in the distribution segment could prevent the entry of non-vertical rivals and avoid the construction of a large national gas market. Vertical and horizontal integration in the distribution segment can trap industry expansion on the path of truncated liberalization. Vertical integration can compromise market competition if anti-competitive practices such as self-dealing are not restrained and monitored. Additionally, it may make the bypass of the transport system attractive, incorporating in the state concession’s asset base an infrastructure that could integrate a broader system. Vertical integration can inflate local tariffs and make it challenging to implement a national gas market. ANP competence for classifying the transport infrastructure can limit vertical integration, pursuing infrastructure expansion based on economic signals.

The case of the gas pipeline “Subida da Serra” in São Paulo is emblematic. The São Paulo state government, the state regulatory agency (ARSESP) and the metropolitan region’s LDC (Comgas) want to build a distribution pipeline with transport characteristics – 31.5 km long in high pressure with a maximum capacity of 16 million m³/day – to connect a new LNG regasification terminal on the coast to Comgas' distribution network. ARSESP classified the pipeline as a distribution network and a state decree (No. 65,889/21) also reinforced its decision, but ANP classified it as a transport gas pipeline in September 2021, based on its regulatory authority under the new federal gas law. The pipeline could allow a new source of gas supply without going through the integrated transport network. The by-pass of the transport grid favors LDC’s commercialization in the São Paulo area, reducing the attractiveness for direct commercialization in the national gas market under deployment. As a result, the São Paulo market may become isolated from the country, with consequences for transportation tariffs and for national commercialization, materializing the truncated liberalization scenario.

In 2021, several states in the Northeast and North regions have already enacted new state laws for natural gas, which conflict with the new federal gas law in crucial aspects for market opening and harmonization of state regulations.²³ The new legal frameworks establish state competencies that conflict with the federal competence of ANP, such as: interference in the classification of new or existing pipelines; imposition of limiting and bureaucratic requirements for direct contracting of natural gas by eligible consumers in the free market; and determination of fees and rules for the free market that increase transaction costs, overlapping the federal competence for commercialization. In this sense, the new state frameworks allow and encourage the verticalization of LDC and the creation of “market islands” in the country, leading to a truncated expansion path or even a wrecked liberalization scenario.

These recent movements point to the evolution of the truncated liberalization scenario, which may undermine the expectation that the third wave of reforms could build a competitive national gas market. The persistence of a dysfunctional regulatory framework in the states can compromise benefits of the gas industry’s expansion for all stakeholders, potentially reducing the average projected impact on state GDP over a 10-year horizon by a quarter vis-à-vis a successful liberalization scenario (FGV CERI, 2019).

Additionally, the divestment of Petrobras in Gaspetro (a subsidiary with shareholdings in 19 LDC in the country) to Compass (Comgas’ holding company) will make the market even more concentrated in the distribution segment. Comgas alone serves 30% of the non-thermal market. After the acquisition of Gaspetro’s shareholding control, LDC’s market share with Compass’ shareholdings will jump to 73% of the nation non-thermal market. The relevant market for distribution cannot be defined as isolated markets in its concession areas or as a potentially neutral regulated activity without considering a potential national natural gas market. Horizontal integration can favor vertical integration between competitive activities and gas distribution, potentially harming competition in the gradual opening process in a context of partial unbundling in the LDC spheres.

Furthermore, a greater horizontal concentration may also hinder the harmonization of state regulations. A company with a robust national presence will be partially subject to federal regulations in gas commercialization, while, at the same time, it can influence fragmented state regulations in a context of poorly structured regulatory agencies, which generally regulate only one LDC and do not take advantage of multi-sectorial regulations to strengthen their regulatory capacity. Thus, the horizontal concentration in the distribution segment can exacerbate the risk of regulatory capture and compromise the transposition of guidelines and good regulatory practices in state regulations. It will be up to ANP to guarantee the harmonization and market opening.²⁴

In addition to the partial unbundling in distribution, Petrobras’ divestment process has not been strategically structured to promote a deeper opening in the downstream segment. Petrobras’ divestment in the distribution segment could have facilitated the review of concession contracts, promoted incentive regulation, and established investment and quality targets. The articulation between the states and Petrobras (controlled by the Union) could also have promoted joint divestments, facilitating the contractual review. On the other hand, the presence of private capital in Gaspetro’s shareholding structure is a complicating factor for reviewing the contracts. In practice, Petrobras' current divestment process did not favor the review of distribution concession contracts.

The new legal framework gives ANP an active role in monitoring the competitive environment (degree of supply concentration) and promoting competition. The main instrument for market opening is the gas and capacity release programs, with a regular offer of contracts with different terms (daily, monthly or annual). ANP can determine the incumbent (Petrobras) to offer short-term contracts, favoring the liquidity of secondary markets and promoting greater flexibility for all agents (Vazquez et al., 2017).

The transition period will be essential for a successful market opening. The Natural Gas Market Opening Monitoring Committee reinforced the importance of harmonizing state regulations and transposition of CNPE’s guidelines in its Guide of Best Practices. The Committee indicates a gradual transition process. The first stage begins with the autonomy and transparency of state regulatory agencies. The second stage involves measures that do not require contractual changes, such as regulating eligible consumers, establishing an efficient tariff structure and quality indicators. The third advanced step includes regulatory capacity building from state agencies and contractual revisions. These steps are essential to pave the way for successful liberalization, overcoming obstacles that could trap the industry’s evolution in a truncated liberalization path. Uncertainties about the role of natural gas in Brazil’s energy transition may further hamper the industry’s potential development in the coming years.

Uncertainties of the role of natural gas in the Brazilian energy matrix

The new legal framework represents an essential step for the Brazilian gas industry’s restructuring, but the future role of natural gas in the energy matrix is still uncertain. Brazil has a high share of renewables in the energy (48%) and power (85%) matrixes and counts on a competitive renewable expansion (wind, solar, and biofuels), which contests the role of natural gas as a bridge fuel in Brazil’s energy transition.

Hydropower is the primary source of the Brazilian power matrix (70% generation on an annual average), which counts with large hydro reservoirs that regulate the seasonality and variability of tropical hydrology. However, the system faces a relative loss of the reservoirs’ regularization capacity due to demand increases and barriers for expanding new hydro reservoirs. This trend, associated with more significant supply variability from renewable generation, makes room for greater thermal power generation, which depends on the merit order curve and the hydrological conditions.²⁵ On the other hand, the gas industry demands a greater level of must-run power generation than the 50% historically practiced limit in the power sector to accommodate the inflexibility of associated natural gas domestic production.

Between 2015 and 2021, natural gas-fired power plants accounted for half of the energy contracted in centralized expansion auctions carried out for the regulated market of electricity distributors, which covers about 70% of national consumption. During this period, the auctions contracted around 9 GWaverage of the new projects that will add 20 GW of new capacity – among which 4.5 GWaverage gas-fired power plants with a total capacity of 6 GW.²⁶ Most of the contracted gas-fired power plants will be supplied by imported LNG, representing a new trend of the gas profile supply in contrast to a growing prospect for domestic resources.

However, the reduction of the European Union’s dependence on Russian gas, due to the consequences of the war in Ukraine, will put pressure on prices in the LNG spot markets over the next few years, compromising the favorable scenario that stimulated the insertion of LNG in Brazilian energy matrix. The new post-2022 international scenario may make gas domestic resources more competitive and strategic for thermal power generation.²⁷ Currently, the expansion of thermal power demand responds exclusively to the conditions of the power sector and the international LNG market, without repercussions for network gas infrastructure, expansion of non-thermal demand, or exploitation of domestic resources.

Despite the increase in thermal power plants contracting in auctions based on competitive criteria, the National Congress determined the contracting of new gas-fired thermal plants in the law that allows the privatization of Eletrobras (No. 14,182/2021) – a state-owned electricity company responsible for 30% of the generation and 50% of transmission assets. The contracting should reach 8 GW of capacity to be installed primarily in locations not yet supplied by natural gas, representing an additional potential demand of 35 Mm3/d. The contracting establishes the location and a high level of must-run generation of 70%. The electricity’s price cap set by the law (US$ 71/MWh) may allow gas monetization at an estimated price (with taxes) of US$7.3/MMBtu, which is the average gas price estimated for the current thermal power capacity.²⁸ Figure 4 shows the implicit price of natural gas with taxes estimated from the variable costs of gas-fired plants in operation. Nevertheless, it may be insufficient to anchor investments in new and extensive gas pipelines. The National Congress approved subsidies for gas pipeline expansion in 2020, but the executive vetoed them.

Figure 4.

Estimated natural gas price of the thermal power plants in operation in 2021. Note. Natural gas price with taxes estimated based on variable cost data from August 2021, considering the specific consumption of each plant (heat rate), variable O&M costs of US$ 3/MMBtu, and exchange rate of R$ 5.20/US$. Source: Own elaboration based on MME (2021) and ONS (2021) data.

Currently, most thermal power plants are installed near gas pipelines or production wells close to power transmission lines (reservoir-to-grid monetization). The use of gas-fired power plants as an anchor to expand gas infrastructure in Brazil may prove to be costly and inefficient due to the country’s continental dimensions, the dispersion of the potential gas market, or its low potential in areas devoid of significant industrial production (north of the country for example).

The determination of expansion without competition goes against efforts to open and modernize Brazil’s natural gas and power sectors, contributing to a wrecked liberalization path. The usual justification relies on the thermal power demand as an anchor to gas infrastructure expansion in locations without gas supply, pursuing the monetization of domestic resources. However, the non-thermal demand has a low potential in these locations to justify the necessary investments. The contracting of gas-fired thermal plants without competition and with must-run generation also displaces competitive renewable expansion and compromises the optimization of renewable resources. EPE estimates that contracting 8 GW of inflexible thermal plants reduces about 20 GW in the expansion of other sources by 2030, especially renewables, besides implying higher generation costs (EPE, 2020).²⁹

The thermal power contracting determined by law has a high probability of not expanding the national non-thermal demand – which remained stagnant during the last 10 years – and raising tariffs for end-consumers. Natural gas insertion without competitiveness and economic fundamentals does not bring welfare gains to consumers (existing and potential) and can compromise the gains pursued by the structural reforms in progress, contributing to the truncated liberalization path of the gas industry. Given the contestability of energy substitutes, the universalization of the natural gas supply should not be a policy goal. Economic signals should guide the expansion of natural gas in the energy matrix, paving the way for a successful liberalization scenario.

The future role of natural gas in the Brazilian energy matrix is still uncertain. The increasing participation of natural gas in the power matrix will be challenged by the competitiveness and abundance of renewable sources in the medium and long term. The prospect for the non-thermal power demand, in turn, will partly depend on gas competitiveness and mainly on the growing industrial consumption, which has remained stagnant in the last decade.

Conclusions and policy recommendations

Influenced by the European reform process, Brazil undertook three significant waves of regulatory reforms in the natural gas industry to liberalize and open the market. The first wave in the 1990s opened the upstream segment but did not encompass specific aspects of the natural gas network industry. In subsequent years, Petrobras expanded its dominant position in all segments. The second wave of reform in the late 2000s introduced a legal framework dedicated to the midstream of natural gas, but it did not achieve in practice the pursued market opening. The third wave of reform begins in the second half of 2010s with voluntary divestments by Petrobras and the articulation of the federal government to improve the regulatory framework. The new Gas Law approved in 2021 consolidates improvements, reinforcing the unbundling between transport and commercialization of natural gas and ensuring negotiated third-party access to essential infrastructure.

Network neutrality collides in practice with fragmented regulatory competencies in the gas industry between the federal government (upstream and midstream) and the states (downstream) and with a partial downstream unbundling. The restructuring has advanced in the midstream (transport) but does not effectively reach the downstream (distribution) as it depends on the improvement of state regulations. Vertical integration is not allowed for TSOs, but LDC can be vertically integrated with competitive segments and expand their market area in horizontal concentration. Commercialization is subject to federal regulation, but the states maintain the competence for regulating the captive market and the rules for the eligibility of free commercialization. This fragmentation reinforces the importance of harmonizing state regulations to create a national gas market in Brazil towards a successful liberalization path.

Winds of uncertainty coexist with waves of reforms in Brazil. The possibility of greater horizontal and vertical concentration in the distribution segment could lead to market foreclosure and lower competitive gains envisioned by the new legal framework and Petrobras’ exit from the network segments, requiring careful analysis and constant monitoring by the antitrust agency. This truncated liberalization scenario may perpetuate obstacles to direct gas commercialization by eligible free consumers, promoting islands of asymmetric non-integrated markets to the detriment of a large, liquid, and competitive national market.

During the transition period, a lower commercialization share of Petrobras challenges the liquidity and flexibility provision in the future gas market. On the other hand, Petrobras will probably maintain its leading role in gas commercialization in the coming years, given the offshore associated gas production profile. ANP federal regulation must monitor the opening process and promote capacity and gas release programs.

Uncertainties also involve the role of natural gas in the Brazilian energy matrix. Non-thermal demand has remained stagnant for a decade while thermal power demand is expanding, sustained mainly by imported LNG. The new scenario for international gas trade after the war in Ukraine in 2022 may put pressure on spot prices and reduce the space for LNG imports by Brazil, favoring the use of domestic resources. Despite the contracting of gas-fired thermal plants in the regulated energy auctions having increased in recent years, there is still a legal provision for contracting an additional 8 GW of inflexible thermal plants. However, it is not certain that this contracting will be viable and neither that their eventual implementation will be effectively translated into anchor-consumption that could enable transport network expansion efficiently or make viable the use of domestic associated gas. In turn, the expansion of the non-thermal power market depends on the competitiveness of natural gas supply and the efficient network infrastructure development.

The success of the third natural gas regulatory reform will depend on the implementation and enforcement of the new gas law, adequate economic signals, the harmonization of state regulations, and the effective opening for the construction of a national gas market.

Footnotes

Declaration of conflicting interests

The author(s) declared no potential conflicts of interest with respect to the research, authorship, and/or publication of this article.

Funding

The author(s) received no financial support for the research, authorship, and/or publication of this article.

ORCID iD

Diogo Lisbona Romeiro

Notes

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