The implementation of the Energy Reform Act in August 2014 marked a new era not only for the Mexico’s domestic hydrocarbons industry, but also for the country itself. Among the changes resulting from the act are the restructuring of NOC Pemex to increase efficiency and the opening of oil and gas value chain from E&P to retail to private foreign and domestic companies. Since 2015, two four-tender rounds have taken place, as well as the first auction of Round 3.1. Three more tenders were scheduled for 2018, but have been postponed. Additionally, in 2016, Pemex began farming out some of its more complex acreage to private companies with greater technological expertise and financial resources.
In addition to the reform, one of the biggest drivers of change in Mexico’s energy industry is growing demand for natural gas. Consumption is expected to rise by 64% between 2013 and 2027. Since 2010, Mexico’s gas imports from the USA have grown by 300%, and the US Energy Information Administration predicts they will double by 2019. Demand is outpacing storage and distribution capacity, a problem that spurred the government to lay out the Five-Year National Integrated Natural Gas Transportation and Storage Plan 2015-2019 which aimed to expand the natural gas pipeline network.
Despite being a crude oil exporter, Mexico has been a net fuel importer since 1998. Pemex has taken steps to stem losses downstream, by partnering with private investors for upgrades and expansions at several of its ageing refineries. Additionally, the country’s new president is promoting a project to build a new mega-refinery in Tabasco. The liberalisation of fuel prices across the country was completed in November 30, 2017. That, coupled with fuel demand growth, has created an environment in which local and foreign, small and large fuel retailers can prosper. In March 2017, BP became the first private foreign fuel retailer in the Mexican market. Since then, several others have entered the sector.
Malaysia’s oil and gas industry is a major pillar of the nation’s economy. The country of more than 23 million citizens is the second-largest hydrocarbons producer in Southeast Asia and the fifth largest exporter of LNG in the world. Malaysia began producing oil in the early 1900s from onshore assets in Sarawak and began moving into shallow-water plays in Peninsular Malaysia, Sarawak and Sabah in the 1960s. New technologies have unlocked new opportunities for more industrious offshore plays in the country’s main producing basins. The government has long pursued development of its maturing and marginal fields and further exploration activities to address a decline in production.
Malaysia’s oil and gas industry is tightly led by its NOC Petronas, which was established in 1974 and holds exclusive ownership rights to all E&P activities. The company’s contributions comprise around 35% of the state’s revenue. State-run upstream watchdog Petroleum Management Unit is responsible for handing out and overseeing production sharing licences in the country. The country has successfully attracted international IOCs interested in taking part in upstream opportunities, including ExxonMobil, Shell, ConocoPhillips, Spain’s Repsol and Japan’s JX Nippon Oil and Gas.
The nation is one of the world’s largest gas producers and exporters. While Malaysia’s NOC is the lead player in gas production and assets, Shell has established itself the second largest producer along with ExxonMobil, Thailand’s PTT Exploration and Production Public Company and Indonesia’s Pertamina having large shares in gas production. The largest domestic destinations for produced gas are the country’s industrial sector, which takes up around 49%, and the power generation sector, which takes up around 50%.
Malaysia boasts an extensive natural gas pipeline network. The majority, known as the Peninsular Gas Utilization network, is located in Peninsular Malaysia. Export of LNG comes from Malaysia’s regasification terminals, which are connected to its major pipeline network and exported to Singapore. LNG is mainly exported to other countries in the Asia Pacific region, with Japan and China being the main importers of Malaysian gas.
The oil pipeline system in the country is limited, and transport of the product remains largely dependent on tankers and onshore vehicles. The country has initiated projects to expand its oil storage capacity based on a capacity shortage in Southeast Asia, particularly in Singapore; Malaysia aims to become a regional storage alternative. Continued investment in refining activity over the last few decades has led to Malaysia generally meeting its domestic requirements. The nation is now looking to expand its refining capacity to supply the region and capitalise on exports.
Kuwait holds the fifth-largest oil reserves in the world, amounting to an estimated total of 101.5 billion barrels. The country’s petroleum export revenue accounts for more than half of its GDP and 95% of government income. Despite the global reduction in crude oil prices, OPEC member Kuwait announced that it would spend USD 155 billion between 2015-2020 on 523 projects through it National Development Plan. USD 40 billion is earmarked for upstream developments and another estimated USD 40 billion for downstream projects. Kuwait Oil Company, the upstream subsidiary of Kuwait Petroleum Corporation, has set the ambitious target of raising its current production rate from 2.9 million bopd to 4 million bopd by 2020.
To accomplish this goal, Kuwait plans to implement EOR techniques and advanced technologies such as solar-powered turbines and steamflooding at heavy oilfields. In March 2014, GlassPoint Solar, producer of the USD 600-million, 1-GW concentrated solar power plant at the Miraah site in Oman, opened its first offices in Kuwait. Prior to the halt in operations at the Partitioned Neutral Zone, Kuwait Gulf Oil Company along with Saudi Arabian Chevron were engaged in efforts to launch a large-scale steamflood project to raise production at the Wafra oilfield. Also anticipated in 2018 is the country’s Lower Fars Heavy Oil Development Programme at the Ratqa oilfield.
To boost downstream capacities, Kuwait’s Clean Fuel Project will refurbish and upgrade facilities at the Mina Al Ahmadi refinery, built in 1949, and the Mina Abdullah refinery, built in 1958. To be completed in 2018, the expanded and combined infrastructure will increase output from 736,000 bopd to 800,000 bopd. In addition to works at the Clean Fuel Project, Kuwait’s Al Zour refinery is expected to come on line by 2019 with a capacity of 615,000 bpd, increasing Kuwait’s total refining capacity to 1.4 million bpd.
The Oil & Gas Year Kuwait 2019 is the most up-to-date and comprehensive report on the country’s hydrocarbons industry. The publication provides in-depth articles to highlight the entire value chain of the country’s hydrocarbons industry, from E&P to the midstream, downstream, power generation, oilfield services, finance and engineering and construction industries.
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Kurdistan Region of Iraq’s oil and gas industry was late to take off, despite discoveries in the region beginning in the 1920s. However, the region was highly successful at attracting major IOCs the mid-2000s, including ExxonMobil, Chevron, Gazprom, Dana Gas and TotalEnergies. The Kurdistan Region of Iraq is an autonomous region of Iraq, although it held a unilateral independence vote in 2017 to mixed international reception. Throughout political upheaval and war it has remained steadfast in its payments to operators, underlining the nation’s resilience.
The region’s hydrocarbons industry is overseen by the Ministry of Natural Resources, which is independent from Baghdad’s Ministry of Oil. However, the country continues to struggle with its independent oil and gas law, which has been defined as unconstitutional by Iraq’s capital and lacks support from the national budget.
Heavy sour crude produced in Kurdistan Region of Iraq (KRI) began to be exported to the Ceyhan terminal in Turkey in 2014 through the KRG’s main pipeline that begins in the Kirkuk region and the DNO-Tawke pipeline. Further gas pipeline infrastructure has been planned to support the region’s planned rise in production.
The KRI requires investment to build up its power generation capacity to support a growing oil and gas industry, which remains the largest industrial consumer of energy.
Kazakhstan holds an estimated 30 billion barrels of oil reserves, along with 1.1 tcm (38.8 tcf) of natural gas. It is among the top 15 countries based on the size of its oil reserves. The majority of Kazakhstan’s hydrocarbons reserves are located in the regions of Kashagan, Tengiz and Karachaganak.
To reach its potential as a global energy player, Kazakhstan is working to maintain a fine balance between the economic interests of its two powerful neighbours, Russia and China. Chinese energy demand continues to surge upwards and will consume Kazakhstan’s robust hydrocarbons output for the foreseeable future.
Iraq’s oil and gas industry has remained stable during the country’s ongoing challenges and conflicts. The country remains the fourth-largest producer of hydrocarbons and the second-largest producer in OPEC. Iraq’s impressive reserves are the third largest in the world behind Saudi Arabia and Iran. The national oil and gas industry is overseen by the Ministry of Oil. The government is involved in E&P activities through the following state-owned entities: North Oil Company, Midland Oil Company, Dhi Qar Oil Company, Basrah Oil Company and Missan Oil Company.
The majority of the country’s hydrocarbons are found in the country’s eastern edge near its border with Iran. The super-fields in the southeast near Kuwait form the greatest concentration of such finds worldwide and contain more than 70-80% of the country’s reserves. About 20% of its reserves are found in the northern region. Production comes predominantly from the nation’s NOCs. The country is looking to up production from its maturing assets, which will require fresh-water injection. Given that fresh water is a rare commodity in Iraq, opportunities exist in building related infrastructure. Iraq’s impressive gas potential has also been largely overlooked, with Iraq relying on gas imports to meet demand. Work continues to bring down gas flaring and develop related transport infrastructure.
Iraq has significant refining capacity, but assets have largely become antiquated and function at around 50% capacity. The aged facilities produce more heavy fuel oil than refined products, which does not match the nation’s demand requirements. The state has discussed imposing measures to move investment focus from its oil and gas production towards developing its downstream capacities to spur direct economic growth for the country.
Another requirement for upping production on Iraq’s oil and gas fields is a rise in power generation capacity. The hydrocarbons industry traditionally takes up 10% of total energy demand in the country, which is expected to rise as output increases. Despite an almost entirely resistant hydrocarbons industry, political turmoil has taken a toll on investment in its power generation sector. Efforts to curb consumption have been made by the government, but further investment is needed to meet the country’s industrial targets.
The Republic of Congo’s oil and gas industry produces the third-largest volume of crude in sub-Saharan Africa. The nation produces mainly oil, with only small amounts of natural gas and condensate liquids. As a net exporter of crude, the majority of the country’s revenues are dependent on fluctuations in oil prices. The OPEC member has long attempted to make the market attractive to foreign IOCs to continue to keep up with its traditional strong production growth.
The country’s hydrocarbons sector is dominated by NOC SNPC Congo, which is the exclusive concessionaire of E&P permits. The State-run company has been joined by many IOCs participating in the upstream sector, including TotalEnergies, Chevron, Perenco and Eni. Independents also play a role in the tapping into the country’s resources. Most producing fields are now offshore, including the prolific Mondo Nord field development.
To curb the country’s reliance on export prices, plans have been made to upgrade its power generation and refining capacity. “The government values the economic diversification of the country and plans to leverage this,” Jean-Marc Thystère Tchicaya, former minister of hydrocarbons for the Republic of Congo, told The Energy Year. “Apart from the use of gas for the production of electricity, the amount of which has been expanding in recent years, other aspects of gas valuation are being studied and offer more opportunities for monetisation.”
The USD 5-billion Congo LNG project is expected to reach a capacity of 3 million tonnes per year. First gas was introduced to the project’s first FLNG vessel, Tango, in December 2023 and the inaugural shipment from the facility was announced in late February 2024.
Brunei’s oil and gas industry has come a long way since the first well was discovered in 1899. The production of hydrocarbons now accounts for around half of the nation’s GDP. The energy industry is overseen by the Petroleum Authority of Brunei Darusallam, which hands out PSCs and ensures participants adhere to policies set down by the state.
Brunei Shell Petroleum is the largest oil producer in the country, accounting for around 90% of oil and gas revenues. A 50:50 joint venture between super-major Shell and the government of Brunei, the integrated energy company BSP has been active in the country since 1929 and operates the 10,000-bopd Brunei Refinery.
New extracting technologies have made the country’s mature fields and deepwater ventures economically viable, and the state is focused on attracting new players into its oil and gas ecosystem. The country’s downstream sector has become equally vibrant with facilities producing LNG, methanol and other petrochemicals. The government has focused on building its petrochemicals capacity as it aims to up production and maximise on the economic potential of its remaining reserves.
Eagle Ford’s oil and gas industry has continued to rise in importance since 2008 when it became the world’s most active shale play, transforming the US’s position in the global energy mix. Since then, production has grown significantly. Eagle Ford accounts for a large share of Texas’ production along with producing fields on the state’s Permian Basin. Texas is the top oil and gas producer in the US, traditionally accounting for just under half of its oil production and a quarter of its natural gas production. The state is also the US’ highest consumer of petroleum products, with its industrial sector taking the lion’s share.
The Eagle Ford shale formation is located in Texas and forms an arc from the Mexican border to around 640 kilometres northeast of Houston and Austin. The 51,800-square-kilometre play is divided into three windows, with the northern section containing mostly crude oil, the central section containing mostly gas liquids such as ethane, propane and butane, and the southern section holding mostly natural gas deposits.
The region has attracted many E&P operators taking advantage of opportunities, with the largest players on the Eagle Ford formation being EOG Resources, ConocoPhillips, Marathon Oil, Chesapeake Energy and China National Offshore Oil Corporation. Players have taken advantage of new horizontal drilling technologies to tap previously untouched plays, with more recoverable resources still untapped in the region.
Production from the Eagle Ford basin has given rise to the US’ largest cluster of oil refineries, predominantly located in ports along the coast of the Gulf of Mexico, consisting of around a quarter of the nation’s oil refining capacity. Gas production has also seen a huge rise in LNG terminals in Texas, accounting for more than half of the country’s LNG export capacity and rising. Despite being a net LNG importer in the past, a large rise in LNG production has seen the US join the ranks as a top global LNG exporter along with Qatar and Australia.
Alongside its coastal marine exports, Texas also boasts a considerable gas pipeline network that pumps the resource across the state, into Mexico and towards the rest of the US. While gas enters Texas’ pipeline system from other states, a larger part of gas is exported, with almost three times more natural gas departing the state than entering.
