Prices Fall on Weather Forecast Changes, Despite Production Declines

Prices Fall on Weather Forecast Changes, Despite Production Declines

Natural gas storage inventories increased 62 Bcf for the week ending July 12, according to the EIA’s weekly report. This is in line with the expected injection, which was 61 Bcf.

Working gas storage inventories now sit at 2.533 Tcf, which is 291 Bcf above inventories at the same time last year and 143 Bcf below the five-year average.

At the time of writing, the August 2019 contract was trading at $2.334/MMBtu, roughly $0.030 higher than yesterday’s close and ~$0.08 lower than last week.

Hurricane Barry caused the market to drop over 1.5 Bcf/d in supply week over week. This happened while Power demand was at its highest levels of the summer. These bullish factors drove prices up last week, but they could not hold, and prices started their decline early this week, falling to the $2.30 to $2.34 range. These declines have come as a result of weather forecast changes, as the last third of July temperature expectations have fallen and are now expected to be cooler. Expect prices to continue to trade on movements in the weather forecasts moving forward.

See the chart below for projections of the end-of-season storage inventories as of November 1, the end of the injection season.

This Week in Fundamentals

The summary below is based on Bloomberg’s flow data and DI analysis for the week ending July 18, 2019.

Supply:

  • Dry gas production saw a decrease of 1.8 Bcf/d week over week. The South Central/Gulf region saw the largest move, decreasing 1.56 Bcf/d due to Hurricane Barry. The region is starting to recover and will do so in the coming weeks as crews resume work in the Gulf.
  • Canadian net imports declined slightly this week, down 0.1 Bcf/d.

Demand:

  • Domestic natural gas demand increased 2.68 Bcf/d week over week. Summer heat once again took demand upward, causing Power demand to increase 2.12 Bcf/d. Res/Com and Industrial demand also increased on the week by 0.37 Bcf/d and 0.19 Bcf/d, respectively.
  • LNG exports saw a slight drop during the week, falling 0.13 Bcf/d, while Mexican exports increased 0.05 Bcf/d.

Total supply is down 2.01 Bcf/d, while total demand increased 2.58 Bcf/d week over week. With Barry causing the drop in supply and summer heat creating stronger demand, expect the EIA to report a weaker injection next week. The ICE Financial Weekly Index report is currently expecting an injection of 35 Bcf. Last year, the same week saw an injection of 24 Bcf; the five-year average is an injection of 40 Bcf.

Prices Pressured Further with Inventory Build, Despite of Crude Draw

Prices Pressured Further with Inventory Build, Despite of Crude Draw

US crude oil stocks posted a decrease of 3.1 MMBbl from last week. Gasoline and distillate inventories increased 3.6 MMBbl and 5.7 MMBbl, respectively. Yesterday afternoon, API reported a crude oil draw of 1.4 MMBbl alongside a gasoline draw of 0.48 MMBbl and a distillate build of 6.2 MMBbl. Analysts were expecting a larger crude draw of 2.7 MMBbl. The most important number to keep an eye on, total petroleum inventories, posted a very large increase of 11.7 MMBbl. For a summary of the crude oil and petroleum product stock movements, see the table below.

US crude oil production decreased 400 MBbl/d last week (due to Gulf of Mexico shut-ins), per the EIA. Crude oil imports were down 0.47 MMBbl/d last week, to an average of 6.8 MMBbl/d. Refinery inputs averaged 17.3 MMBbl/d (0.17 MMBbl/d less than last week’s average), leading to a utilization rate of 94.4%. Although crude oil withdrawal is higher than expected, large total petroleum stocks build is pressuring prices. Prompt-month WTI was trading down $0.28/Bbl, at $57.34/Bbl, at the time of writing.

Escalating tensions in the Middle East between the US and Iran and the impact of Tropical Storm Barry on Gulf of Mexico production had pushed prices above the $60/Bbl level last week, and prices traded in the narrow range of $59-$60/Bbl until the beginning of this week. Prices started declining on Monday, falling nearly 1%, and sharply declined on Tuesday, dropping nearly 4% due to bearish factors, creating a perfect storm. IEA’s newest report, released on Friday, stated that in the first half of 2019, demand grew at the slowest pace since 2011, due primarily to the contraction in manufacturing. Meanwhile, global oil stockpiles grew in the first half of 2019, with world supply exceeding demand by 0.9 MMBbl/d in spite of the OPEC+ reductions. The report and the warning by IEA about a possible supply glut in 2020 certainly increased the bearish sentiment. Prices also got support on signs that the impact of Barry on Gulf of Mexico production would be short-lived, as producers are already starting to resume operations. Two other catalysts that pushed prices down nearly 4% were; Chinese industrial output and retail data showing the country’s slowest quarterly economic growth in decades and the potential easing of tensions between the US and Iran following remarks by US President Donald Trump and US Secretary of State Mike Pompeo. The disappointing Chinese data dimmed an already gloomy outlook for global economic growth and appetite for crude demand, pushing prices down further. Pompeo’s statement on Iran being prepared to negotiate on its missile program eased the fears of a military conflict arising and tensions further increasing between the countries, which potentially could have impacted supply from the Strait of Hormuz.

OPEC+ production cuts and the increasing tensions in the Middle East, potentially threatening supply from the Strait of Hormuz, have been driving the bullish sentiment. Prices could see further pressure due to the bearish IEA report and thawing tensions between the US and Iran, offsetting these bullish elements for the time being. Continuously increasing US production, along with the increasing bearish elements in the market, could initially take prices down to $56.00/Bbl, where prices will likely find support. However, further thawing of US – Iran tensions, as well as additional data showing weakening global economic growth, could push prices to levels below $55.00/Bbl.

Petroleum Stocks Chart

Callon Buys Carrizo Oil & Gas in an All-stock Deal Valued at $3.2 Billion

Callon Buys Carrizo Oil & Gas in an All-stock Deal Valued at $3.2 Billion

Callon Petroleum has agreed to acquire Carrizo Oil & Gas for $3.2 billion, with shareholders of Carrizo set to receive 2.05 shares of Callon for each share they hold. That represents $13.12 per Carrizo share based on Callon’s closing common stock price on July 12 and a 25 percent premium to Carrizo’s prior day closing price. Pro-forma, Callon shareholders will own 54 percent of the combined company and 46 percent will be held by former Carrizo owners.

“This deal checks a lot of the boxes on what seems to make sense for corporate-level E&P M&A,” said Drillinginfo M&A analyst Andrew Dittmar. “You have two small-to-midsize companies active in the Delaware Basin combining to build economies of scale, reduce G&A expenses, and hopefully accelerate the move to positive free cash flow.”

With the all-stock consideration, Callon is building scale while preserving cash on the balance sheet for development and avoiding having to attempt raising additional capital from a frozen Wall Street. It can also leverage the slightly higher valuation its stock carries over Carrizo. While not exactly a “merger-of-equals” they are similar sized companies and the post-deal shareholder split will be a relatively even with 54 percent buyer, 46 percent seller.

From a valuation perspective, the acquisition looks very reasonable. A 25 percent premium to a prior close is a moderate premium for a public E&P buyout. After adjusting for the value of Carrizo’s existing production and Eagle Ford acreage, Callon is acquiring the Permian leasehold at a bit under $20,000 per acre. That compares favorably to the $30,000 per acre or more seen in other public E&P buyouts in the Permian.

“If there is anything slightly surprising about this deal, it would be that Callon is willing to pick up the Eagle Ford assets of Carrizo and lose its status as a Permian pure-play which the market seems to favor,”  said Dittmar. “With more mature wells, the Eagle Ford assets do provide some stability to the combined company’s production base and supply much-needed cash flow, but we wouldn’t be that surprised to see Callon look to monetize these assets and return its focus exclusively to the Permian provided they can find a buyer in this market willing to pay a fair price.”

There continues to be a strong case for further consolidation among the shale drillers, especially in the Permian. Other companies will be closely monitoring how the market takes this deal and how badly Callon is beat up for announcing an acquisition in the current low-growth Wall Street mood. The market is already taking what would be expected to be the initial reaction and selling Callon off to the tune of ~15 percent. We will have to wait a bit and when the dust clears see what the longer-term implications are for its stock. Check back on our blog for more details and commentary from our expert M&A analysts as we follow this deal and others.

The Week Ahead For Crude Oil, Gas and NGLs Markets – July 15, 2019

The Week Ahead For Crude Oil, Gas and NGLs Markets – July 15, 2019

CRUDE OIL

  • US crude oil inventories posted a large decrease of 9.5 MMBbl last week, according to the weekly EIA report. Gasoline inventories decreased 1.5 MMBbl, while distillate inventories increased 3.7 MMBbl. The total petroleum inventories showed a decrease of 3.8 MMBbl. US crude oil production increased 100 MBbl/d last week per EIA. Crude oil imports were down 0.3 MMBbl/d to an average of 7.3 MMBbl/d versus the week prior.
  • Prices regained their bullish momentum primarily on the effects from Hurricane Barry in the Gulf of Mexico, which forced US Gulf operators to shut in nearly 1.0 MMBbl/d. The bullish reduction of crude oil inventories in the EIA’s data release on Wednesday also contributed to the gain.
  • These bullish elements brought further support to prices beyond the existing factors provided by the geopolitical unrest in the Mideast, which escalated after Iran’s threats to restart its deactivated centrifuges and increase uranium enrichment. The deployment of a British frigate to escort a BP tanker through the Strait of Hormuz, which was challenged by Iran boats, brought further concerns about this critical shipping lane for crude oil supplies.
  • Despite these elements and the continuation of the OPEC+ supply cuts through Q1 2020, the IEA noted some bearish implications for the market in the longer term. In its report released on Friday, the IEA cited that in the first half of 2019, demand grew at the slowest pace since 2011, due primarily to the contraction in manufacturing. Meanwhile, global oil stockpiles grew in the first half of 2019, with world supply exceeding demand by 0.9 MMBbl/d in spite of the OPEC+ reductions. Though the agency forecast for 2019 is steady, it will require a massive rebound in consumption, three times the level of the first half of the year. With demand continuing to deteriorate, OPEC may be forced to reduce output further in order to attain market balance.
  • This report exemplifies the primary reason the market has not had a more prominent rally given the tensions in the Mideast. Global economic concerns regarding the lack of growth and the ongoing unresolved tariff negotiations between the US and China (the world’s two largest economies) place a dark cloud over any longer-term gains in price.
  • The CFTC report was issued on Monday and Friday last week for the reporting periods of July 2 and July 9. The combined reports showed a reduction in the Managed Money short positions by 6,943 contracts, while the long sector increased by 8,883 contracts. The speculative long position is gaining, but the hesitancy in adding to positions at a significant level shows the market is not convinced that prices will remain strong over an extended period of time.
  • The market internals represent a more neutral to slightly bullish bias with the gains from Hurricane Barry. Volume was higher, while open interest was flat on the week. Prices this week will focus on results of any damage to the Gulf region oil assets and the geopolitical issues lingering in the Mideast.
  • Prices may expand the bid up to the highs of last week at $60.94/Bbl up to $63.81/Bbl, but these areas will find sellers. The highest weekly close since the middle of May should bring a brief expansion early this week. The concerns over the IEA report may bring some selling into the price action, but prices will likely find support in the $56.00/Bbl area. As discussed last week, this market may need time to consolidate the gains as it waits for any additional Iran drama to further support price movements. That said, as the Iran issues become more muted, expect declines based on weak global economic demand to have a greater impact on prices longer term.

NATURAL GAS

  • Natural gas dry production showed a decrease of 1.13 Bcf/d. These declines come from the impact of Hurricane Barry, which took Gulf production down 0.78 Bcf/d, split between the Gulf and Louisiana. The remaining declines were seen in the Northeast. Canadian imports increased by 0.03 Bcf/d.
  • Res/Com demand increased 0.08 Bcf/d, while power demand increased 1.182 Bcf/d (a result of excessive heat in the South and Central regions of the CONUS). Industrial demand decreased 0.03 Bcf/d. LNG exports declined 0.12 Bcf/d, likely due to Hurricane Barry, while Mexican exports gained 0.18 Bcf/d. These events left the totals for the week showing the market dropping 1.10 Bcf/d in total supply and total demand increasing by 1.90 Bcf/d.
  • The storage report last week showed the injections for the previous week at 81 Bcf. Total inventories are now 275 Bcf higher than at the same time last year and 142 Bcf below the five-year average. With demand increasing and supply decreasing, expect the EIA to report a weaker injection this week.
  • Weather forecasts continue to show above-average temperatures in the coming 10 days throughout the Central and Eastern regions of the US. The longer-term forecast maintains heat in the South and Central regions, with some moderating temperatures in the Northern Plains, Great Lakes and Northeast.
  • Hurricane Barry will impact the market this week, and while the initial response was a reduction in production from the Gulf operators evacuating rigs, the longer-term impact will be on the reduced temperatures associated from the storm’s rains. The market will start to get insight as to the effect on power demand early this week as the flow data becomes transparent.
  • The CFTC report was released twice last week; the report on Monday reflected position changes as of July 2, and the report last Friday reflected position changes effective July 9. Combining those reports had the Managed Money short position reducing positions by 18,753 contracts, while the long position reduced positions by 3,431 contracts. It would seem that the speculative trade may be loosening some of their conviction of $2.00 gas.
  • Prices held firm last week, staying above $2.40 for most of the week. Prices closed the week above the 50-day moving average (a closely monitored indicator of intermediate-term trend) for only the third time in 2019 (the other two occurring on either side of the Memorial Day holiday). Market internals changed to a more neutral bias as volume was significantly higher week over week. Total open interest remained nearly flat according to preliminary data from the CME.
  • The fundamentals-based trade will have to assess the impact from Hurricane Barry. Weather forecasts are always subject to change but currently show a declining demand picture two weeks out. Any further extension of the rally will have to overcome the selling at $2.49 as witnessed last week with the failure to push through. This area ($2.49) up to $2.522, and then $2.56, will continue to find significant selling in the coming weeks. On the other side, declines during the coming heat will find buyers down between $2.30 and $2.263.

NATURAL GAS LIQUIDS

  • Prices strengthened across the board week over week. Ethane gained $0.013 to $0.151, propane gained $0.013 to $0.458, normal butane gained $0.036 to $0.532, isobutane gained $0.090 to $0.682, and natural gasoline gained $0.042 to $1.155.
  • US propane stocks decreased ~241 MBbl the week ending July 5. Stocks now sit at 76.9 MMBbl, roughly 13.3 MMBbl and 14.7 MMBbl higher than the same weeks in 2018 and 2017, respectively.

SHIPPING

  • US waterborne imports of crude oil fell for the week ending July 12, according to Drillinginfo’s analysis of manifests from US Customs and Border Protection. As of July 15, the data showed that PADD 3 imports increased to nearly 1.8 MMBbl/d, while PADD 5 imports fell to slightly more than 910 MBbl/d. PADD 1 imports rose to 492 MBbl/d.

  • Imports from Mexico were the driver of the PADD 3 increase, reaching more than 900 MBbl/d with an additional 50 MBbl/d imported to PADD 5, the highest level since August 2018.

The Rewards of Staying in Zone?—Geosteering Part III

The Rewards of Staying in Zone?—Geosteering Part III

The industry spends a fair bit of money on geosteering—the process of matching logging-while-drilling data to open-hole log data to ensure that the wellbore is drilling through the most productive rock.

It can be a nerve-wracking process—I know because I did some geosteering on Austin Chalk wells around Dilley, Texas, in the early 90s, mostly by sample descriptions. The technology for doing what we do today was rudimentary, novel, and raw.

Today’s operators can, by-and-large, trust their geosteering contractors or in-house staff to keep them pretty much in their defined target or landing zone, and the geosteering mavens routinely deliver great results.
I’ve taken it as an article of faith that the more the wellbore is in zone, the better the well will be.
However, now that I’ve looked at a fair bit of data, I’m not so sure that’s true.

I looked in DI Play Assessments at wells in the Delaware Basin with a landing zone = Wolfcamp A XY.

There doesn’t seem to be a clustering of out-of-zone wells. Instead they are spatially distributed in the same manner of wells that have higher in-zone percentages.

With the help of our geology team, I got this cross section of the Wolfcamp A XY landing zone. The orange line is the top of the Wolfcamp A XY, the blue marker is the top of the Lower Wolfcamp A.

Note that the section gets shalier as you move from north to south, and the section thins by about 90’.
The map below generally confirms the trend and shows that both out-of-zone wells and in-zone wells are generally targeting the same lithologies.

However, it’s very hard to see meaningful differences in well performance as measured by Peak BOE. The map below compares Peak BOE for wells with less than 5% of wellbore in zone to wells with greater than 75% of wellbore in zone.

Graphing BOE by % in zone shows no meaningful difference in median First 12 months BOE—139,000 First 12 months BOE for less than 75% in zone versus 143,000 First 12 months BOE for more than 75% in zone.

Bulk correlating log metrics like density or neutron porosities doesn’t yield a great correlation with production performance.

There’s little correlation between gross perforated interval and First 12 months BOE.

There is, however, what looks to be a good correlation between lateral length and First 12 months BOE.

So, if your company man calls in and says the geosteering job didn’t stay in zone as much as hoped…don’t worry too much…unless you only drilled 3000’ of lateral.

Agree? Disagree? Send your thoughts to me at mnibbelink@drillinginfo.com.

Brazil, Is Now the Time?

Brazil, Is Now the Time?

“Brazil is the country of the future…and always will be.” This quote can be traced back to 1947 and is as true today as it was then. However, the country is undergoing a serious cultural and economic transformation since the election in 2018 of right-wing president, Jair Bolsonaro. The country’s hydrocarbon industry is also at a similar crossroads as the current administration attempts to implement a series of free market reforms to attract outside investment and lessen the near monopoly power Petrobras continues to exert on the sector a full two decades after it was “opened.” The Bolsonaro administration is making bold and transformative moves to give the hydrocarbon sector a makeover. This could create unprecedented opportunities for players in the sector and could change Brazil from “the country of the future” into the country of opportunity for today’s hydrocarbon exploration and production industry.

 

Bolsonaro Era

PSL party candidate, Jair Bolsonaro, won Brazil’s presidential runoff election on October 28, 2018 with 55 percent of the vote, besting Fernando Haddad of the leftist workers party (PT) by about 10 percent. The PT governed Brazil from 2003 until 2014 under four consecutive terms of Lula and Dilma Rousseff.

The 2018 presidential election was unprecedented and highly polarized. Haddad was not confirmed as the PT party candidate until September replacing the PT party founder and former president Luiz Inacio Lula da Silva. Lula was the frontrunner in the election but declared ineligible to run due to serving a 12-year prison sentence for corruption. In short, Bolsonaro was elected amidst a prevailing mood of disgust by the electorate over corruption in the political system, economic stagnation, and a loss of faith in the liberal policies of the PT government and its allies.

 

Where’s the Beef?

 

Brazil is already the world’s eighth largest producer of hydrocarbon liquids and the third largest producer in the western hemisphere. However, the crown jewel of Brazilian resources remains the pre-salt, where other than Lula Field, production has barely started. A 2015 study of the pre-salt polygon, covering most of the Santos and Campos basins determined at that time that the area contained at least 176 Bboe of undiscovered, recoverable resources. The study was released by Cleveland Jones and Hernane Chaves of the National Institute of Oil and Gas (INOG) at Rio de Janeiro-State University. The figure was classified as P90 and a second P10 figure was also given as 273 Bbo. The INOG study estimate is the only major public assessment of the subsalt polygon’s potential. The 2015 INOG study estimate is 54 percent higher than the previous study by INOG in 2010 which estimated a P90 of 114 Bboe and a P10 of 288 Bboe. The average field size in the pre-salt polygon was also determined to be 246 MMboe.

 

Top 20 Producing oil wells in Brazil, all in pre-salt, 19 in Santos Basin

Top 20 Producing oil wells in Brazil, all in pre-salt, 19 in Santos Basin

 

Upstream Rounds and Opportunities for All

 

Not all the opportunity in Brazil lies in the pre-salt. There are four different types of bid round offerings that will be held in Brazil in the second half of this year alone, in addition to the Petrobras divestment.

The most conventional of these rounds is ANP Round 16 to be held on October 10, 2019. The royalty tax regime round will offer 36 blocks in five offshore sedimentary basins (Campos, Camamu-Almada, Jacuípe, Pernambuco-Paraíba, and Santos) totaling 29,300 sq km. The Campos Basin with 13 blocks totaling 12,004 sq km is expected to draw the most interest. The region is attractive based on lots of oil gas infrastructure in place and pre-salt potential.

ANP Round 16 Offered Blocks in Campos and Santos Basins

ANP Round 16 Offered Blocks in Campos and Santos Basins

Current Operators in Campos and Santos Basins

Current Operators in Campos and Santos Basins

A new system just implemented by the ANP is referred to as Permanent Offer of Areas established for open acreage. The bid opening date is set for September 10, 2019 for the first cycle of blocks. The program will tender exploration blocks previously bid or returned, and it officially launched on June 27. The ANP expects to announce by August 16 the final lineup of approved sectors that will be part of the first cycle. At last report the bid had 600 exploration blocks and 14 areas with marginal accumulations to be offered with environmental approval.

The round is designed to attract investment in mature basins with an ongoing supply of available blocks, to encourage more small and medium companies in the sector to help develop the industry, and to stimulate exploration in new frontier basins. The Permanent Offer Round consists of the ANP setting a minimum price and work commitment for each block. With the publishing of a new decree recently, all onshore areas, including new blocks, will be offered via the Permanent Offer program. Companies can express interest in acquiring the block by paying the guarantee for its work program for each block they wish to acquire. If the registered company is the only one paying the guarantee, they will automatically acquire the block at the minimum set price and work program. If more than one qualified company pays the guarantee for a given block in the round, then a competitive bid process is held.

Two different rounds are planned for the pre-salt in 2019. In June the ANP approved Production Sharing Round 6 in the deepwater pre-salt and the contract model. The round will offer the Aram, Bumerangue, Cruzeiro do Sul, Sudoeste de Sagitário blocks, and the Norte de Brava Block in the Campos and Santos basins with a total of 8,640 sq km. All blocks are inside the pre-salt polygon. The signing of the final contracts is scheduled for March 2020. The bid will be held on November 7, 2019.

For the production sharing contracts effective in this round, the signature bonuses are fixed, and the winning bidder is determined by the highest offered percentage of profit oil to the state. Petrobras on January 14, 2019, exercised its preferential right to operate three blocks in the round with 30 percent selecting the Aram, Norte de Brava, and Sudoeste de Sagitário blocks. Registration for the round is open until September 19.

 

ANP 6th PSC Round Offered Blocks

ANP 6th PSC Round Offered Blocks

However, the truly impactful round that everyone in the industry is eyeing is the Onerous Assignment Surplus Production Rights Bid, also called the Transfer Rights area, in the Santos Basin pre-salt polygon where bids are due on November 6, 2019. The registration period for the round began on June 13. The round will offer the Atapu, Búzios, Itapu, and Sepia blocks. Petrobras has carried out significant activities in all fields and has started production in Buzios. The CNPE set the total signature bonus payments at 106.56 billion reais (US$ 26.73 billion), of which 68.2 billion reais (US$ 17 billion) is for Búzios, 22.86 billion reais (US$ 5.5 billion, first oil expected 2021) for Sépia, 13.74 billion reais (US$ 3.5 billion, first oil expected 2020) for Atapu, and 1.77 billion reais (US$ 440 million, first oil expected 2023) for Itapu. The signature bonus is fixed and does not affect the bid award criteria, which is solely based on the highest percentage of profit oil offered to the government. The current Onerous Assignment contract gave Petrobras a production cap of 5 Bboe for seven ultra-deepwater blocks in exchange for Petrobras stock. The round now offers private companies the rights to produce the surplus volumes above the production cap that Petrobras has discovered in the contract area. Those surplus volumes are estimated to be 6 Bboe or higher. In May 2019, Petrobras indicated to the CNPE that it wished to exercise its right of first refusal with a 30 percent interest on the Búzios and Itapu blocks.

The numbers here are staggering. Almost US$ 27 billion expected in signature bonus money and a minimum of 6 Bbo in partially developed oil reserves is sure to attract the attention of oil and gas majors the world over. However, substantial opportunities are also present in the Petrobras divestment and in the downstream, midstream, and gas market sectors.

 

Onerous Assignment Surplus Production Rights Bid Blocks (in orange)

Onerous Assignment Surplus Production Rights Bid Blocks (in orange)

 

Petrobras Divestment

On June 12, Petrobras CEO, Roberto Castello Branco announced an increase in the money the company expects to raise in its divestment program of non-core assets. The program is now projected to generate US$ 35 billion over the next five years. The upward revision by Petrobras took place just after the supreme court ruling that made it much easier for state companies to sell subsidiaries without the authorization of the legislature thereby boosting the divestment program. In January Petrobras announced it had resumed a process to divest about 70 percent of its 254 mature onshore and shelf fields.

Although divestment is targeted toward mature, onshore, and shelf and marginal producing assets, for the right price almost anything is on the table. Production and especially exploration have declined sharply in these assets over the past decade or more, due to underinvestment by Petrobras as the company struggled with debt and the need for large investments to develop its pre-salt discoveries. When put together, the following factors should provide the “perfect storm” of opportunity for some small to medium players in the sector.

  • Recent favorable supreme court ruling
  • Petrobras debt and high investment obligations in the pre-salt
  • An administration that wants more diversity, free enterprise, and investment in the sector
  • Underinvestment and relative neglect of mature producing properties

However, the opportunities don’t end here. The biggest opportunities may lie in the midstream, downstream, and gas market sectors where Petrobras has continued to hold monopoly power despite the opening of the sector 20 years ago. The current administration is making it a priority to change this.

Refinery Sale

On June 28, 2019, Petrobras announced some details regarding the divestment process for four of its refineries and associated assets. The first refineries to be sold are Rnest, Repar, Rlam, and Refap. Divestment of the other four Petrobras refineries is planned for launch in the second half of 2019. Experts in the sector have expressed the opinion that the Petrobras refineries will not attract the interest of big oil companies but will be more attractive to fuel distributors and refining specialists in the sector. On June 11, 2019, Petrobras committed to the 100 percent sale of eight oil refineries and related fuel transportation assets with a total capacity of 1.1 MMbo/d. When the sale is completed, Petrobras will have seven refineries remaining in Brazil.

Recent Pipeline Sales

On June13, 2019, Engie and Petrobras announced the conclusion of the sale of the Petrobras 90 percent stake in the gas pipeline company Transportadora Associada de Gas (TAG). The deal involved the acquisition of 90 percent of the share capital of TAG by the French company ENGIE valued at approximately US$ 8.1 billion. TAG has a gas pipeline network of 4,500km with a transport capacity of 2.612 MMcfg/d. With the completion of the deal, almost 70 percent of the domestic gas pipeline network of about 9,500km, is now controlled by two private companies. In 2017, Petrobras sold the New Transportadora do Sudeste (NTS) pipeline network of 2,000km to Brookfield. The completion of the sale of TAG was made possible by a recent decision from Brazil’s Federal Supreme Court allowing the sale of state-owned subsidiaries without congressional approval.

Gas Market

 

The biggest opportunity in Brazil’s hydrocarbon sector could involve the transformation and development of its natural gas market. As the country commits to reducing its carbon footprint, it will begin producing large amounts of associated gas with its pre-salt oil production and development. Much of it can be used for the country’s energy matrix where natural gas only accounts for 11 percent of current energy usage.

In late June 2019, Brazil’s National Council for Energy Policy (CNPE) presented 24 guidelines for the opening of the natural gas market as well as new annual targets for greenhouse gas emission reductions for fuels. The CNPE proposals aim to increase unbundling throughout the natural gas value chain and most of all, create conditions for access not just to gas pipelines, but also to all the essential infrastructures of the sector, such as outlets, processing units, and LNG terminals. The proposals are directed at opening the market and promoting competition.

Change = Opportunity

 

Whichever direction you turn and whatever your perspective on the industry in Brazil, one must realize that, “the times they are a changin.” Rarely do you have so many factors in play at the same time opening so many different doors in so many different areas as in the Brazilian hydrocarbon sector today. The large companies and majors have the pre-salt E&P with its huge investments and even larger rewards potential. As Petrobras is forced to focus on this aspect of the business and improve its balance sheet, it must sacrifice some smaller and neglected hydrocarbon assets to divestment. Meanwhile, the door to exploration and discovery of new resources is opened even wider by conventional bid rounds such as ANP Round 16 and a new program that could revolutionize the sector like the Permanent Offer of Areas which allows open acreage to be claimed by any company willing to pay the guarantee and perform the work commitments. On top of this a sympathetic, pro-business administration in power is taking action to dismantle long-standing pipeline, gas market, and refining monopolies by Petrobras in the country as well as an underdeveloped natural gas market that is virtually certain to expand. All of this adds up to the definite conclusion regarding Brazil that for hydrocarbons, “The future is now.”

Contact: scott.stewart@drillinginfo.com