NGW Magazine

31 AUGUST 2020

VOL 5, ISSUE 16

NAT U R A L GA S WOR L D M

A

G

A

Z

I

N

E

NEWS. ANALYSIS. THE INSIDE TRACK.

Colombia aims for more imports

Iraq pins hopes on gasfields

US-Mexico gas flows rise

Costing carbon: methane in the EU

China redesigns its gas supply with a focus on pipelines Gas: the tension multiplier in the eastern Med Bolivia’s impasse on exports

INDEX 18

3

BLEAK FUTURE FOR BOLIVIAN GAS

EDITORIAL: SUPPING WITH THE DEVIL

4

21

CHINA CREATES A COMMON CARRIER

COLOMBIA EYES SECOND TERMINAL

7 MYANMAR’S CHINESE GAMBLE

10

24

GAS FROM AKKAS

GAME-CHANGERS FOR US-MEXICO GAS

14

27

GAS AND THE EEZ MED

EUROPE TACKLES METHANE EMISSIONS

SUPPING WITH THE DEVIL Events in eastern Europe will harden Western attitudes against gas EDITORIAL

Deeply troubling scenes of state brutality against protesters in Belarus have been broadcast by journalists risking life and limb. The rounding-up, imprisonment and torture of bystanders and demonstrators alike by the ‘security’ forces is a continuing outrage.

Its president, Alexander Lukashenko, who has called Covid19 a psychosis, is holding on to power for now after yet another rigged election. He has appealed for support to Russia, another country that is no stranger to rigged elections.

With Ukraine severing its political ties with Russia – except for continuing gas transit payments – Belarus is the last buffer between Russia and the West. This makes both interference and non-interference risky for European leaders. They have plenty of actual problems of their own to deal with at home as the social and economic damage of the responses to Covid-19 continues to mount.

Russia’s president Vladimir Putin too is in a quandary: no friend of Lukashenko, who has played him off against the EU and received cheap Russian oil and gas, he is understandably also keen to keep this state onside. Running the country will also have a high financial cost for Russia, already hammered by the precipitous and unexpected fall early this year in both price and volume of its exports.

While it is too early to say how and if a regime change will happen, it is likely that any heavy-handed intervention by Russia will put relations with the EU on even colder setting. This will disadvantage gas within the bloc, by association with its biggest single supplier.

And further east is the highly suspicious case of Alexei Navalny, officially the leader of the anti-corruption-focused opposition party but whom Putin refuses to name. German doctors have confidently attributed the “internet blogger’s” condition to poisoning by one or more of a range of substances.

He remains in an induced coma at time of press but reports say he is being treated with the same drug that was used to cure the Russian victims of the Salisbury poisonings, the Skripals. Other victims of Russian poisoning – such as Alexander Litvinenko on British soil – were not so lucky. And the Kremlin, or its friends, have other methods at their disposal too, as Boris Nemtsov’s death illustrates.

Navalny’s support comes from his courageous exposure of cut-price real estate deals and embezzlement by Putin’s circle, at the expense of the nation as a whole. Putin will either look weak – not much can happen involving access to poisons like that without his say-so – or complicit in the crime, if one is proven. Putin’s spokesman said there were no grounds for an investigation, since no poison has been discovered.

3

These political events are not directly related to gas, but the commodity, for all its benefits, has always suffered from its association with some of the undemocratic and often oppressive regimes – not only Russia falls into that category – that happen to export it, and this is the biggest problem that it faces.

Nuclear and renewable energy escape this charge although neither is without major problems of their own, particularly at the start and end of their life-cycles. These problems are however of a technical, not a moral nature. How often have we read in defence of renewable energy that car batteries, solar panels, wind turbines and so on – and huge amounts of minerals will have to be produced in poorly regulated regions to make them – will find alternative uses after their natural life has ended; or they will be safely disposed of?

Renewable energy is also being asked to do a lot: the expected surplus has to produce hydrogen as well as recharge batteries to justify the cost of building enough to cope with electrification.

The thrust of such special pleading – that as-yet-undiscovered technology will become cheap – does not of course extend to gas, in the reasoning of its opponents. Carbon capture and storage is discounted and we are airily informed that investments in pipelines and so on “lock in” a source of energy that damages the planet at every stage of the process.

The European Investment Bank and many other institutions are giving warning of an end to such financing, even if for now this infrastructure – notably in the Balkans – is needed to ensure ‘diversification of supply.’

It has been shown in the case of Nord Stream 2 that politics cannot be kept out of gas and even out of energy law. These are bad precedents to set, but the fact that the US may be acting illegally if it applies sanctions does not mean that the US is also wrong morally to try to limit the flow of Russian gas to Europe.

The use of sanctions is just realpolitik, the aim being to stop the money remitted ending up funding the sort of activities that its European customers also wish to avoid, even as they decry Washington’s interference.

And the fact that the US, with its idle LNG export terminals, is a likely beneficiary of such a reduction of Russian imports does not necessarily explain its actions: it has been opposed to Russian export growth for many decades.

Gas of course will continue to be needed – and in great quantities – as coal and nuclear are phased out, and not only as the carrier of hydrogen. And Russia will continue to provide a lot of it, especially as European climate objectives and environmental activists obstruct – or raise the cost of – domestic production.

But Europe’s gas industry will find it ever harder to justify its purchases of cheap gas if it ignores the political price.

— NGW

SUPPING WITH THE DEVIL

CHINA CREATES

A COMMON CARRIER

Beijing’s expropriation of gas producers’ pipeline assets to form a separate, common carrier is designed to foster upstream development and so help realise the government’s goal of self-sufficiency.

Shi Weijun The biggest shake up of China’s oil and gas industry in two decades is under way as the country aims to prise open the pipelines to all comers. Beijing has launched its long-awaited pipeline reform with the multi-billion-dollar transfer of major energy infrastructure assets to the country’s national pipeline company.

Two national oil companies, PetroChina and Sinopec, agreed in July to swap various assets – including pipelines, storage and import terminals – worth a combined Rmb 391bn (US$56bn) for cash and shares in the operator, known as PipeChina. Those deals, plus cash injections from other investors, will value PipeChina at Rmb 500bn once they close by the end of September – making the state-owned firm one of the largest pipeline companies in the world.

The asset transfers will end PetroChina and Sinopec’s near-duopolistic control of China’s midstream sector and could

4

usher in a domestic upstream boom in the coming years.

No longer incentivised to keep out gas produced by other companies, the two NOCs will have to sharpen their upstream focus while paving the way for more players in order to foster competition.

The reform represents the most significant overhaul of China’s energy industry since the domestic NOCs started listing on domestic and foreign stock exchanges in the early 2000s.

PetroChina stands to net Rmb 268.7bn in the form of Rmb 119bn in cash and a 29.9% stake in PipeChina, making it the largest individual stakeholder. Sinopec will receive RMB 122.7bn in the form of RMB 52.7bn in cash and the second-highest shareholding of 14%.

The remaining shareholders in PipeChina will be a mix of state-owned holding companies, the state pension fund as well

VOL 5, ISSUE 16 | 31 AUGUST 2020

The move to create a unified pipeline network is fundamentally about boosting the share of gas within China’s energy mix to a targeted 15% by 2030.

as the country’s insurance investment fund, sovereign wealth funds, the regulatory watchdog for China’s biggest state-owned enterprises, and offshore oil and gas explorer China National Offshore Oil Corp. Their stakes will range from 2% to 12.87%.

PETROCHINA TO BEAR THE BRUNT The impact of the transfer will be bigger for PetroChina than Sinopec, as the former owns and operates the biggest pipeline network in the country. The length of PetroChina’s domestic oil and gas pipelines measured 87,144 km, comprising 53,291 km of gas pipelines, 20,091 km of crude, and 13,762 km of oil products, according to its 2019 annual results.

The infrastructure assets to be spun off from PetroChina account for 8.9% of the total assets held by its parent, China National Petroleum Corp, according to an estimate from S&P Global Ratings. By comparison, Sinopec will be shedding 3.43.6% of its total assets.

Among the pipelines that PetroChina is divesting are the three West-East pipelines, which have a combined capacity of 73bn m³ and form the backbone of China’s gas transport network. The cross-country trunklines, originating in Turkmenistan and carrying gas from other Central Asian former Soviet republics, have transported more than 540bn m³ to date. Sinopec’s list of assets includes its Sichuan-East China pipeline that links gas fields in southwestern China to the thriving Yangtze River Delta on the eastern seaboard.

The newest project that PetroChina is involved in is the Power of Siberia, which is now ramping up; but more pipelines from Russia to China are planned. PipeChina has already taken over work on the domestic cross-country pipeline that distributes gas from Power of Siberia around China – it said in late July that it had started building the southern segment of the China-Russia East pipeline that will run from Yongqing in China’s northern province of Hebei to the financial hub of Shanghai in the Yangtze River delta.

PETROCHINA POST-REFORM The pipeline reform raises question marks over the future of PetroChina as its dominance of the distribution network is coming to an end. A short-term concern is how PetroChina will continue to weather losses incurred on the domestic resale of imported gas.

The company lost Rmb 30.7bn on such sales last year, up from a loss of Rmb 24.9bn in 2018.

5

PetroChina’s pipeline business has generated steady returns that cushioned the impact of the import losses, but the burden will be magnified once its pipeline assets have been transferred. PetroChina’s management indicated in July that it was in talks with regulators on a solution between both parties, in which the company might be able to offload some of the losses in future.

At the same time, PetroChina will be relieved from the heavy spending on building long-distance pipelines as this responsibility will soon fall to PipeChina. In the longer run though, pipeline reform could be a prelude to an eventual restructuring of PetroChina given Beijing’s desire to nurture a more competitive upstream sector.

Pipeline reform effectively represents an assault on PetroChina’s oil and gas distribution monopoly, so Beijing may take a similarly hardline stance on the company’s upstream dominance since it accounts for 70% of domestic gas production. The idea – which so far remains no more than speculation among industry insiders – would be to break up PetroChina to create a fragmented but more dynamic industry of risk-taking upstream firms.

There is a longstanding view among some experts in Beijing’s policy-making circle that gas output has underwhelmed because of an inefficient and risk-averse three-way monopoly in the Chinese energy industry.

One official from the state central planning department (the national development and reform commission) has previously told NGW that Beijing had erred in building up PetroChina as an upstream national champion, as such a company was never the correct structure for a country that does not export oil or gas.

The official pointed to how the US, with its highly fragmented and competitive industry, has become a net exporter of both oil and gas – and is on the verge of energy self-sufficiency.

The official said parts of PetroChina’s assets – particularly those in gas – should be spun out to create a “critical mass” of independent players and wildcat well drillers that could absorb private capital and in theory increase output more efficiently.

PREMIUM VALUATIONS PetroChina and Sinopec both received premium valuations for their assets, easing shareholder fears that they would not be compensated fairly for the divestment forced upon them by Beijing. For instance, PipeChina agreed to pay a 43% premium

China creates a common carrier

above the book value of Sinopec Kanton’s 944-km Yulin-Jinan gas pipeline, resulting in a final cost of Rmb 3.2bn.

This was far above estimates among analysts that ranged from a 20% premium to none at all. Overall, PetroChina will get 1.2 times book value for its assets while Sinopec will get 1.4 times in the deals.

The consolidation of China’s transportation and storage infrastructure under PipeChina sits at the centre of reform efforts by the president-for-life Xi Jinping. His government wants to boost domestic energy production and distribution in the world’s largest energy market. The move to create a unified pipeline network is fundamentally about boosting the share of gas within China’s energy mix to a targeted 15% by 2030.

To that end, the Chinese government wants to see lower gas prices and considers greater upstream competition. By forcing its NOCs to divest their midstream operations, Beijing hopes to remove a major barrier for other firms to invest in upstream.

Whereas PetroChina and Sinopec monopolised the distributed network to convey their own oil and gas supplies, PipeChina is expected to act independently and treat all producers fairly on capacity access.

This will make it easier for new E&P entrants to monetise any oil and gas resources that they discover and effectively end a decades-long monopoly over the upstream sector by China’s three NOCs. There are implications for the downstream segment too, as improving third-party access to supply infrastructure will make it easier for companies to supply and offtake oil and gas from China’s network. This will help liberalise China’s LNG import market, as emerging LNG importers will be able to import inexpensive spot volumes and receive them at the regasification terminals to be divested by the NOCs. There is still significant work to be done for PipeChina as it will need to manage conflicting interests among the companies contributing assets to become an efficiently operating entity.

Some say it could take two years, others as long as five years, to overcome these rivalries and get things running smoothly.

6

SPENDING BOOST FOR E&P PetroChina and Sinopec will earmark the bulk of the proceeds from their sales for a special dividend, but a considerable portion is likely to go towards upstream. Assuming that one-third of the cash is allocated for reinvestment, this would be an additional Rmb 39.6bn – or equivalent to a fifth of the Rmb 200bn that PetroChina has budgeted for capital expenditure in 2020.

PetroChina spent Rmb 230bn on exploration and production alone in 2019.

The additional cash to plough into the upstream business is important as energy security has moved up the political agenda in Beijing over the past two years. Most recently, Chinese vice premier Han Zheng said during a tour of PipeChina in August that China should continue to deepen the reform of its oil and gas system to ensure a stable oil and gas market and national energy security.

Han’s comments came after the NDRC and the national energy administration issued a joint statement in June that re-emphasised energy security across a number of industries.

The statement said that within oil and gas, the focus will remain on increasing domestic exploration and development efforts, particularly in shale gas. Pipeline infrastructure buildout was also highlighted, to increase pipeline reach and ensure supply protection.

China’s quest for domestic energy security led to a record investment of Rmb 82.13bn in oil and gas exploration last year, up by 29% from 2018, while investment in hydrocarbon production surged by 24.4% to Rmb 252.71bn, according to the ministry of natural resources in late July.

According to the ministry, China booked an additional 1.12bn metric tons (7.868bn barrels) of oil in place in 2019, up by 17.2% year on year, while new gas in place reserves booked last year dropped by 2.7% over the same period to 809.1bn m³.

China creates a common carrier

MYANMAR’S

CHINESE GAMBLE

Its pipeline exports of gas to China reach regions far from the coast; but tiny Myanmar risks being drawn into an unequal relationship with the world’s biggest buyer.

Gordon Feller

When China’s president, Xi Jinping, kicked off his 2020 foreign travel program in January, his first stop was Myanmar – even while Covid-19 had a firm grip on his own country.

Asia’s superpower cares so much about one of the poorest countries in the world because it is keeping a close watch on the security of its gas imports. And its pipeline connections with Myanmar are rising to the top of its list.

Gas shortages on China’s mainland are severe, even for an economy where growth has stalled. Analysis by Bloomberg Intelligence found that foreign suppliers could expect to meet three quarters of this year’s demand. That is a significant rise from 57% in 2017. The shift from coal to cleaner-burning fuels is one key driver. In LNG imports China now exceeds all other individual countries.

Compared with other key supplies, Myanmar’s gas is a gift: cheap and reliable. Gas from the Middle East by contrast has to cross vast oceans including the Malacca Straits with pirates adding

7

to the insurance bill; and on top of that come expensive LNG carriers. These imports are creating serious economic burdens, while the lower prices that come from pipeline deliveries of natural gas will aid the country’s post-pandemic economic recovery.

Myanmar’s Zawtika and Shwe fields are where the gas for China now resides. Myanmar’s energy ministry once posted an announcement: “Most of the gas produced within Myanmar… is exported to China and Thailand, so the domestic gas demand cannot be sufficiently satisfied.”

This is why Chinese interest in the town of Kyaukpyu is so critical: it is the chosen site of a new port to connect with two pipelines transporting gas and oil to China. Kyaukpyu is a relatively insignificant coastal town along the Bay of Bengal in Myanmar’s western-most state of Rakhine.

Despite the global recession brought about by the pandemic, and despite Myanmar’s relative isolation from the world, the national government is still anxious to construct this

VOL 5, ISSUE 16 | 31 AUGUST 2020

Nepal Bhutan Myanmar’s Three Special Economic Zones

Source: Myanmar Capital

Bangladesh

China Myanmar

India

Laos Kyaukpyu SEZ Thilawa SEZ

Thailand Vietnam

Dawei SEZ

mega-project: a $7.3bn deep-water port and $2.7bn industrial area. The latter will be in a special economic zone (SEZ) at Kyaukpyu, along the coast of the Bay of Bengal. Agreements to undertake this mega-project have been signed with Chinese state-owned firms – and these contracts have set off alarm bells around the world.

China has remained committed to the Kyaukpyu projects primarily because the town is the terminus of two assets: a $1.5bn oil pipeline and a parallel natural gas pipeline running to Kunming, capital of southwestern China’s Yunnan Province.

Unlike any of the other major infrastructure projects related to Kyaukpyu, construction work on the pipelines has moved forward despite significant local opposition. They were built between 2010 and early 2015 by China National Petroleum Corporation and Myanmar Oil and Gas Enterprise – both state-owned firms – with CNPC as the majority stakeholder. The gas pipeline became operational in 2013 and is capable of exporting 12bn m³/yr to China.

After a two-year delay, the oil pipeline started up in April 2017. Some reports indicate that it can carry 22mn barrels/yr, which amounts to about 6% of China’s oil imports. This pipeline project is part of China’s strategic Belt and Road Initiative (BRI) to reduce its reliance on imports through the Strait of Malacca.

Pirates apart, China wants to prevent an adversary such as the US from closing the strait.

Cambodia

based in Naypyidaw, is forced to turn to Chinese loans in order to fund its share of the port and SEZ. When combined, these could amount to 5% of national GDP. In 2016, subsidiaries of China’s Citic Group, including China Harbor Engineering Company, won contracts for two major projects in Kyaukpyu – the dredging of a deep-sea port and the creation of an industrial area in an SEZ. The port project is valued at $7.3bn and the SEZ at $2.7bn. Under the terms of the deal, Citic will build and then run the project for 50 years with a potential extension of another 25 years.

Negotiations on Kyaukpyu however predate the BRI: Citic signed initial memorandums of understanding (MOUs) for the harbour project and a railway connecting the SEZ to southern China in 2009. However, they languished amid political sensitivities in Myanmar surrounding Chinese investments following the 2011 suspension of the Myitsone dam project and violent

China - Myanmar Oil and Gas Pipeline

Source: rmgbd.net

Kunming Kunming Bangladesh

Wanding

THE THREAT TO MYANMAR Despite fears that this new project could eventually be used to enable and facilitate Chinese military access, project advocates say that there are political and legal restrictions in place in Myanmar which make this unlikely. The project is focused on helping China avoid the vulnerable Strait of Malacca and on aiding the development of Myanmar’s southwestern hinterland.

Like many major projects in China’s trillion-dollar BRI, there are well-founded fears that the project could grant China a high degree of financial leverage over Myanmar. This is especially worrying for critics of the project if the national government,

8

China

Myanmar

India

Vietnam Naypyitaw

Bay of Bengal Shwe gasfield

Laos

Kyaukpyu Thailand

Myanmar’s Chinese gamble

protests starting in 2012 over the Letpadaung copper mine.

The railway MOU was canceled in 2014 while the port and SEZ industrial area projects are moving forward, but slowly and with considerable pushback within Myanmar. Only in October 2017 did the two sides reach an agreement on ownership of the port project after Citic agreed to drop its stake from 85% to 70%.

Ownership stakes in the SEZ have yet to be finalised.

PIPELINE SHORT-CUT Building a deep-sea port at Kyaukpyu makes considerable economic and strategic sense for China in its drive to develop its inland provinces. Shipping goods from Europe, the Middle East, Africa, and India to Kyaukpyu and then overland to Yunnan could save thousands of miles. It would be far more efficient than sailing all the way through the Strait of Malacca and the South China Sea to ports along China’s southern and eastern coasts, and then travelling overland to China’s western provinces.

Unsurprisingly, in December 2017, Myanmar’s leader Aung San Suu Kyi and Xi agreed in Beijing to establish a new China-Myanmar Economic Corridor connecting Kyaukpyu and Kunming. No details were released, but the project would likely include construction of a road and perhaps the restart of the suspended rail project. Mandalay, Myanmar’s second-largest city and the traditional hub for trade with southern China, would serve as a staging-post along this new economic corridor. Ultimately it seems Chinese planners envisage the Kyaukpyu - Kunming oil and gas pipelines as just the first step in a new trade route that could change the economics of China’s hinterland.

While the establishment of a deep-sea port at Kyaukpyu makes sense for China, any benefits for Myanmar will depend in large part on the success of the accompanying SEZ. Without successful industrial projects in the SEZ, Kyaukpyu could become little more than a waystation for goods headed to Yunnan. The former government of Myanmar under Thein Sein promoted three large SEZ projects to boost the country’s economy. Of these, the Japanese-led Thilawa SEZ just outside Yangon is the only one already up and running. Another, the joint Thai-Japanese Dawei project along the southern coast, has faced constant financial troubles but continues to move forward slowly. That puts Kyaukpyu third in a three-way race, and it is unclear whether the zone, with its late start and distance from Myanmar’s commercial and economic heart of Yangon, will be able to lure sufficient investment.

There are concerns among some in India and the West, as well as within Myanmar itself, that China could leverage the port at Kyaukpyu for military purposes, but such worries are premature at best. Myanmar’s leaders, both military and civilian, are famously jealous of the nation’s sovereignty and will not accept a permanent foreign military presence, whether from China or anywhere else. In fact, the country’s 2008 constitution expressly forbids the deployment of foreign troops on its soil.

That means that commercial investment in the port at Kyaukpyu is not likely to lead to a permanent Chinese presence such as in Djibouti or, reportedly, Gwadar, Pakistan. Chinese naval assets could certainly pay calls to the port from time to time, as they do at Colombo in Sri Lanka, which is also majority-owned by a Chinese company. But such port calls should not by themselves be cause for concern.

SLIPPERY SLOPE TOWARDS DEBT Critics fear that closer ties between Myanmar and China could put the smaller nation on a slippery slope by providing China a dangerous level of economic leverage over Myanmar owing to the accumulation of too much Chinese-funded debt. Chinese loans and large-scale investments have proven highly controversial in other regional states, such as the Maldives, where Beijing has been accused of using debt as a lever, forcing governments to make political and economic concessions that go against its national interest.

Such fears are not unfounded. The Myanmar government’s 30% stake in the Kyaukpyu port amounts to $2.2bn. If it takes a 50% stake in the SEZ, that would bring its total responsibility for the projects to $3.5bn, or about 5% of GDP. As Yun Sun at the Stimson Center has pointed out, if the Myanmar government cannot handle that level of financing, it will likely turn to Chinese loans.

Concerns about Chinese economic leverage help explain the continued local opposition to Kyaukpyu and the slow rate of progress. One of the driving factors behind Myanmar’s decision

9

to move toward civilian government in 2010–2011 was a worry about overreliance on China amid continued Japanese and Western sanctions.

For the time being, China remains a major but not overwhelming economic presence in the country. China has a major footprint in Myanmar, both in trade and investment, but so do other partners like Japan that provide Myanmar with a significant degree of manoeuvrability. That is not likely to change in the short term, though the potential debt burden from Kyaukpyu bears watching.

Kyaukpyu is of considerable strategic and economic value for China as it seeks to speed development of Yunnan and its other inland provinces. That value is centered on the development of a deep-water port and the construction of accompanying road and rail links to supplement the pipelines already running to Kunming.

Whether the project also boosts Myanmar’s economic growth depends upon the success of the accompanying SEZ, and the terms under which it takes shape.

MYANMAR’S CHINESE GAMBLE

GAS FROM AKKAS Iraq is holding talks with potential international partners in the west of the country to increase gas production and so cut gas and power imports from Iran.

Ian Simm

News broke in May that Iraq would allow companies from neighbouring Saudi Arabia to invest in the development of Akkas, the country’s largest non-associated gas field. The announcement by finance minister and acting oil minister Ali Allawi was aired by Saudi Arabian news channel Al Arabiya, and quickly generated headlines about Saudi Aramco, the world’s largest oil producer, making its first steps into the development of overseas assets in the upstream sector.

However, the talks had been running since at least August 2019, when a deputy minister, Hamid al-Zawbai, said Baghdad was speaking to Aramco and Saudi Basic Industries Corp (Sabic) for Akkas and the planned Nebras petrochemical complex, respectively. Since then, Aramco has acquired 70% of Sabic in a $69.1bn deal.

Despite the high-level sign-off, Muhammed Abed Mazeel Al-Aboudi, director general of the reservoirs and fields development directorate at Iraq’s ministry of oil (MO) told NGW in late August that “Aramco [has] not yet discussed the project with us.”

10

Noting that Akkas remains “on the table”, Al-Aboudi explained that the ministry is “looking for partner for [current operator, South Korea’s] Kogas,” adding that the Koreans have been asked to start production from the field or to leave. He added that there has been interest from US companies and while discussions are “going forward” on multiple fronts, Akkas will be awarded to international companies.

AKKAS IN FOCUS The field is around 30 km from the Syrian border in the restive Anbar Province of the Western Desert. Few wells have been drilled in the area, but the Akkas-1 well revealed 3,133 metres of predominantly siliciclastic sequence.

The field’s resource is estimated at 5.6 trillion ft³ (159 bn m³), with recoverable reserves thought to be around 3-3.5 trillion ft³.

Akkas was awarded to a joint venture between Kogas and Kazakhstan’s state KazMunaiGas during the 2010 licensing

VOL 5, ISSUE 16 | 31 AUGUST 2020

The development of Iraq’s gas fields will be key to the country weaning itself away from continued dependence on supplies from Iran to power the domestic electricity grid.

round, with the partners awarded a technical services contract with a remuneration fee of $5.50/barrel of oil equivalent (boe).

This anticipated achieving 400mn ft³/d of production, but the field’s location has been an obstacle to progress.

ANBAR ANXIETY In 2013, work was suspended for three months when an armed group attacked facilities at Akkas, killing three members of staff and kidnapping two others. Progress was again halted between 2014 and 2017 when Anbar fell under Islamic State control.

Following the militant group’s expulsion, in November 2017 the MO requested that Turkey’s TPAO and Kogas resume work.

This was followed by the award by the Korean firm to UK-based Petrofac of a contract to modify the front-end engineering and design (Feed) for the field’s gas plant.

Given the situation in Anbar, announcements of oil and gas developments are few and far between. In November 2019 though, Russia’s Stroytransgaz Oil was awarded a 35-year exploration and production deal for Block 17, north-west of Samawah. This was noteworthy because first, Stroytransgaz is a pipeline rather than exploration specialist; and second, Block 17 was previously unheard of, and appears to have been recently re-designated along similar lines to the pre-Gulf War Block 4.

The Russian firm signed a deal during Saddam Hussein’s reign, though this was never ratified.

The block covers an area through which a $5bn, 1mn b/d oil pipeline was expected to run, carrying oil produced from the Rumaila oilfield in Iraq’s Basra Province to the Jordanian port of Aqaba. This would perhaps have explained Stroytransgaz’s involvement, but Jordan and Iraq agreed on a revised route via Najaf rather than Haditha in 2016, and the MO invited expressions of interest in an engineering, procurement and construction contract for the Basra-Najaf string but the project has since stalled. The Jordanian cabinet approved the pipeline in principle in February last year.

DEVELOPMENT PLANS Despite the historic instability, Baghdad is keen to press on with the development of its Western Desert gas resources. Through his own social media network, Al-Aboudi said in July that despite safety guarantees from the local and central government, Kogas remains “concerned [about proceeding…] with the development of the field (the Upper Khabour only)”.

11

He added that the MO “will ask other international companies very soon to develop the field” with the option to extend to the Lower Khabour, Akkas and Hot Silurian formations and/or neighbouring blocks to reach a plateau of 1bn ft³/day.”

Al-Aboudi noted that “the reservoirs & fields development directorate encourages all international companies to ask the petroleum contracts and licensing directorate about the field and neighbouring opportunities. We estimate huge dry gas and gas condensate reserves.”

ENERGY SECURITY IMPERATIVES The development of Iraq’s gas fields will be key to the country weaning itself away from continued dependence on supplies from Iran to power the domestic electricity grid. This comprises around 1mn ft³/d as well as 1.2-1.5 GW of electricity, for which it has relied on rolling sanctions waivers from the US. Historically, Iraq has been one of the world’s worst culprits for natural gas flaring, lacking connectivity to transport and thus monetise much of the associated gas from oil production. Baghdad’s focus has historically been drawn to the production of oil, given its comparatively low storage and transport costs.

However, efforts are afoot in Baghdad to change this, with the most notable being the South Gas Utilisation Project (SGUP) on which a final investment decision was taken by Anglo-Dutch major Shell early last year.

At the heart of SGUP is a $17.5bn project under development by the Basra Gas Co, a joint venture of state-owned Basrah Oil Co, Shell and Japan’s Mitsubishi, which will treat, process and distribute associated gas from the giant Rumaila, West Qurna 1 and Zubair oilfields.

Meanwhile, in January this year, Baghdad approved the award of six blocks in the south-west and south-east of the country that had been provisionally licensed in April 2018. The licences were apportioned to a mix of Chinese and Emirati companies, with the majors passing up on the opportunity to bid in the 11-block licensing round.

The acreage apportioned was highlighted by the Gilabat-Qumar and Khashim Ahmer-Injana non-associated gas fields, which went to Dana Gas affiliate, Crescent Petroleum.

The company has extensive experience of operating assets in the Kurdistan Region of northern Iraq, and its award marked a notable shift in policy, with Baghdad historically reluctant to allow firms to operate assets in both Kurdish and federal territory.

Gas from Akkas

Former prime minister Adel Abdul Mahdi said at the time that the acreage awarded would allow for 750mn ft³/day of gas production by 2023, partly replacing Iranian gas imports. However, with little work having so far been carried out on the fields, it appears unlikely that they will be capable of replacing imports from Iran soon.

SUM OF THE PARTS Meanwhile, Al-Aboudi also spoke of the potential of the Al-Mansouriyah gas and condensate field, which is being fast-tracked into production. The field is in Diyala province, 110 km north-east of Baghdad, with the first phase being developed to produce a combined 100mn ft³/d of gas.

Al-Mansouriyah was awarded to a consortium led by Turkish state petroleum producer TPAO during the 2010 licensing round, with Kuwait Energy Co (KEC) and Kogas taking minority stakes.

The consortium accepted a remuneration of $7/boe.

Al-Aboudi said: “Target plateau production is 320mn ft³/d.

The field was returned back to the Midland Oil Co. due to the situation in the area. Currently the area is under the control of the Iraqi Army and safe to work.” Upon reaching their respective

12

plateau production levels, the combination of Akkas and the Al-Mansouriyah could provide around 700mn ft³/d of gas.

Meanwhile, Baghdad has plans to complement its existing electricity supplies by connecting the Iraqi grid to that of its Gulf neighbours, further emphasising the pivot away from Iran. The announcement follows an agreement by Jordan and Saudi Arabia to connect their grids.

Speaking to the Washington, US think-tank Atlantic Council late August, Allawi said that Iraq would “significantly” reduce its reliance on its eastern neighbour. In a nod to the challenge of replacing the large volumes of energy it now imports from Iran, Allawi said: “It is unlikely we can find a short term substitute”, but suggested that the Gulf grid hook-up could be a “medium-term” solution. He added: “The dependence on Iranian electricity and energy will begin to trail down significantly sometime next year.”

Iraq has also recently agreed contracts with US firm GE and Siemens of the US to overhaul the country’s electricity grid.

Perhaps on completion of these projects, in addition to expected progress at Akkas, Al-Mansouriyah and other smaller gas fields, Iraq will be capable of weaning itself off supplies from its eastern neighbour.

Gas from Akkas

28th World Gas Conference 21-25 June, 2021 Daegu, Korea

Submission Deadline: October 19, 2020 We welcome industry experts from around the world to submit an abstract for the chance to be selected to speak at the global gas conference. For more details on how to submit visit www.wgc2021.org

Call for Papers Enquiries

Sponsorship Enquiries

General Enquiries

papers@wgc2021.org

sponsorship@wgc2021.org

info@wgc2021.org

HOST ASSOCIATION

HOST PARTNER

PRESENTED BY

GAS AND THE

EEZ MED Territorial disputes persist in parts of the eastern Mediterranean where gas has not been found – and which would not be commercial even if it were.

Charles Ellinas

To all appearances the growing tensions in the eastern Mediterranean are all to do with disputes over exclusive economic zones (EEZ) and therefore the control and exploitation of the resources of oil and gas that, by all indications, might enrich the region.

But that appears to be the only blessing in an area otherwise besieged with conflicts, teetering on the brink of war.

Following intervention by Germany’s chancellor, Angela Merkel, Turkey’s president Recep Erdogan agreed at the beginning of August to “pause” offshore surveys south of the Greek island Kastelorizo (Figure 1) and to open a dialogue with Greece over their disputes.

14

VOL 5, ISSUE 16 | 31 AUGUST 2020

Fig. 1 — Greek island Kastelorizo off the Turkish coast

Source: Global Security Review

TURKEY

Ro

Kas

GREECE

Mediterranean Sea

Kastelorizo

Strongyli Preparatory discussions to initiate such dialogue were in progress, but following the EEZ delineation agreement signed between Greece and Egypt August 6, Turkey pulled out of discussions and returned to its original offshore survey plans.

Given global developments, especially in the energy sector, are such conflicts justifiable, or is the region stepping back in time? Europe is moving away from fossil fuels and even though the transition to clean energy may take a long time, with the increasing penetration of renewables the world has entered an era of abundance of energy resources, including natural gas.

The problem at the heart of this whole saga is this: with plentiful cheap gas supplies in the global markets expected to continue for a long time, eastern Mediterranean gas is likely Fig. 2 —Major gas finds in the eastern Mediterranean

15

to continue to be too expensive to exploit commercially. The perceived riches locked in at the bottom of these disputed and fiercely-contested seas might never be economic.

In addition, the probability of significant hydrocarbons existing between Cyprus, Kastelorizo, Crete and Egypt’s EEZ boundary –the bone of contention between Greece and Turkey – is low.

The areas considered to be of higher potential for hydrocarbon discoveries are uncontested waters: Egypt’s entire EEZ; the Levantine Basin that includes parts of Egypt; Israel; Cyprus and southwest Crete. Finds in these areas include Tamar, Leviathan, Aphrodite, Zohr, Glaucus and Calypso and southwest of Crete (Figure 2). The areas claimed by Turkey have mostly low probability of hydrocarbon presence.

Source: Bloomberg

Gas and the EEZ Med

These are realistic agreements, unlike the extreme Turkey-Libya memorandum that completely ignores the rights of islands, even Crete.

This raises the question: what are the countries of the region striving for? Do they suffer from an unrealistic perception of the riches or are they reacting to Turkey’s determination to impose its will on the region? Whatever it is, natural gas appears to have little to do with it and it would be counter-intuitive for a war to flare up in a region with low potential for economic gas exploration and production.

GREECE-EGYPT EEZ AGREEMENT Following the Greece-Italy agreement, the Greece-Egypt EEZ agreement is based on the United Nations Convention on the Law of the Sea (Unclos), recognising island rights and reinforcing internationally-accepted maritime principles.

Welcoming the agreement, Egypt’s foreign minister Sameh Shoukry said it allows both countries to move forward in developing oil and gas reserves in their EEZs. But before this can happen the EEZ must be delineated, including Cyprus. It is only after that that they will be able to divide their respective EEZs into exploration blocks, which eventually would enable the two countries to proceed with licensing rounds. It is only after that exploration and drilling can start.

But Turkey’s foreign ministry reacted immediately, denouncing it as null and void. It claims the deal falls within Turkey’s continental shelf and “violates” Libya’s maritime rights.

two countries without taking into account at all the rights of the islands such as Crete. The memorandum was condemned by the EU and the US as “counterproductive and provocative”. However, Turkey used this as the basis of defining its “continental shelf” claim (Figure 4).

The Greece-Italy maritime agreement, signed in June, was based on co-ordinates agreed in 1977 before the international implementation of Unclos. It appears to limit the influence to islands in the Ionian and deviate from the equidistance principle.

Fig. 3 — Eastern Mediterranean EEZs

Source: GreekCityTimes

ITALY Greece-Italy EEZ

GREECE

Fig. 4 — Turkey’s claims

TURKEY

Source: Turkish Ministry of Foreign Affairs

Turkish Petroleum Licence Areas (2009 - 2012) Turkish Petroleum New Licence Areas

WHAT HAS BEEN AGREED UP TO NOW None of the EEZ claims in the east Mediterranean are clear cut, with the right completely on one side or the other. Even globally, experience shows that the application of Unclos eventually leads to agreements through negotiation, compromise and often referral to international courts. This region will be no different.

So far EEZ agreements have been reached by negotiations between directly involved parties: they are not declared unilaterally. Declarations ignoring the claims of other states, however tenuous these may be, cannot solve the problems and cannot prevail.

Formalised EEZ agreements reached so far are those between Cyprus and Egypt, Cyprus and Israel and Greece and Italy (Figure 3). All these agreements are based on Unclos.

Cyprus also reached an agreement with Lebanon, but this has not yet been formalised owing to EEZ disagreements between Lebanon and Israel.

Turkey and Libya signed a maritime memorandum in November 2019, which defines a dividing line between the

16

So called Egypt-Greece Boundary Agreement Turkish Cypriot Licences Oruc Reis Survey Area

The Greece-Egypt agreement, on August 6, which provoked the wrath of Turkey, has only partly defined the EEZ boundary between the two countries – about 40% – between the 26th and 28th meridians (Figure 4). It does not extend to the Libyan EEZ and to the east it avoids the area affected by Cyprus and Kastelorizo. This seems to have been done at the request of Egypt, as it considers these issues to be complex, especially in relation to Turkey.

Also, the agreed boundary does not seem to correspond to the equidistant line between Egypt, Crete, Karpathos and Rhodes, but in roughly a 56%:44% division in favour of Egypt.

However, it is a positive first step.

Gas and the EEZ Med

Turkey’s seismic survey vessel Oruc-Reis, accompanied by Turkish navy frigates

Source: AFP

Even though the Greek-Italian and Greek-Egyptian agreements leave ambiguities, they also allow room for future negotiations on the remaining EEZ boundaries – and perhaps, in the end, for referral to the International Court of Justice (ICJ) at The Hague. However, they are of great importance as a basis for future negotiations.

These are realistic agreements, unlike the extreme Turkey-Libya memorandum that completely ignores the rights of islands, even Crete.

ROOM FOR NEGOTIATIONS? Following the frenzy of the first three weeks of August, Greece and Turkey have been brought back from the brink of naval confrontation. Turkey’s seismic survey vessel, Oruc-Reis, continued roaming the seas south of Kastelorizo (Figure 5) until August 23, but it was a Pyrrhic victory, if one can even call it that.

Turkey’s aggressive maritime pursuits have not won it any friends or any international support – quite the contrary. The international community in its entirety is condemning it. Led by the EU, notably France and Germany and with US and UK support, calls for settlement of these disputes through negotiations are growing stronger by the day. But so far this group has avoided stronger action, including sanctions.

As the situation has developed, Turkey has not even gained anything tangible through this belligerence. Some say that it has reinforced its claims to the contested areas, allowing the country to enter negotiations from a position of strength. But that plainly is not the case. These claims can be addressed only through negotiations, and, as and when these come, everything will be on the table, subject to the levelling influence of international law.

Greece’s restraint has faced considerable internal criticism but it has won Greece universal international support. Through this the risk of naval confrontation has been averted, possibly for the longer-term.

Discussions between the two countries may resume late August/early September, following de-escalation and German/ US mediation. The challenge remains to agree an agenda for negotiations. The likelihood may be that – in the event of a

17

deadlock – these disputes are eventually referred to international courts, possibly the ICJ, for mediation. This is the sensible way forward, that with EU and US help may prevail.

Greece welcomed the opportunity but made it clear that the immediate agenda should be confined to resolving maritime disputes. This was confirmed by its prime minister Kyriakos Mitsotakis. He said Greece intends to enter into dialogue with Turkey under strict conditions and within the framework set by international law on the issue of EEZ delineation. He went on to say that if the dialogue ends in disagreement, then the case should be referred to the ICJ. Following Turkey’s strong reaction to the Greece-Egypt agreement, it is not now clear how Turkey intends to proceed.

But on August 13, Erdogan said that the solution to these problems can only come through dialogue and negotiation, and he does not seek any “adventures” in the region. He proposed a “meeting of all the eastern Mediterranean states for a fair distribution of the region’s energy resources”. How credible these statements are will be seen shortly.

The only sensible way forward is dialogue and Germany’s continued mediation may eventually enable this. Nothing else is so likely to lead to the settlement of EEZ disputes.

At their joint meeting on August 20, French president Emmanuel Macron and Merkel confirmed that they “want the de-escalation of tensions and respect for sovereignty” adding that “we must have a positive agenda in order for Turkey to re-engage in dialogue with Europe.” Macron reiterated that diplomacy without red lines does not exist, but military power without diplomacy does not produce results either.

IMPACT ON CYPRUS To a certain extent, the potential dialogue between Greece and Turkey and the EEZ boundary agreement between Greece and Egypt sideline Cyprus.

The first may lead to an agreement between Greece and Turkey that could eventually impact Cyprus’ EEZ. And yet Cyprus is not party to this dialogue, other than indirectly through its close relationship and co-ordination with Greece.

This will be even more so if the dispute ends-up being referred to the ICJ, which is quite likely. The court will consider only the issues referred to it, jointly agreed between Greece and Turkey.

The Greece-Egypt agreement only addresses the EEZ boundary between the two countries, not accounting for Cyprus and Kastellorizo. This was done at the request of Egypt as it considers these issues to be too complicated. This leaves open questions that can be dealt with only through negotiations with Turkey.

In the meanwhile, Turkey is continuing and escalating intervention in Cyprus EEZ. It has issued a new Navtex and is proceeding with seismic exploration east of the island, in an area that includes Cyprus’ offshore blocks 2 and 3 licensed to two of Europe’s biggest producers, Eni and Total. This is a clear message that Turkey considers Cyprus a completely different issue, leaving the island in a vulnerable situation until a solution can be found to the Cyprus problem.

Gas and the EEZ Med

BLEAK FUTURE FOR BOLIVIAN GAS

Bolivia’s goal of becoming ‘the energy heart of Latin America’ appears increasingly unrealistic despite the gas exporting country’s central location and substantial natural gas potential.

Vincent Lauerman

State-owned Yacimientos Petrolíferos Fiscales Bolivianos (YPFB) did a commendable job of increasing the country’s marketed gas production by almost three-fourths to 58mn m³/d in the eight years between nationalisation in 2006 and 2014 (Figure 1). But the former government of Evo Morales was accused of “milking the cow but feeding it no grass” as YPFB has focused on boosting production to the detriment of exploration, for which it has neither the necessary financial muscle nor technical expertise.

As a result, after firming up reserves in formations previously discovered by international oil companies, Bolivia’s proved gas reserves have been in free-fall since 2012, declining by almost a third to 213bn m³ in 2019 (Figure 2). This in turn has contributed to Bolivian marketed gas production dropping by over a quarter between 2014 and 2019, to 42mn m³/d.

To his credit, Morales saw the writing on the wall, and in the middle of the last decade he allowed the energy ministry to

18

loosen contract terms for foreign oil companies. This was part of his attempt to re-energise gas exploration in the country. Bolivia was fortunate in that most of the international companies that were present – including Spanish Repsol, Anglo-Dutch Shell and French Total – remained after nationalisation, and simply adjusted themselves to the newly less profitable contracts for current production.

But Bolivia’s efforts are being hampered by declining foreign markets, compounded by political turmoil since the disputed presidential election last October and then the economic fallout from the global Covid-19 pandemic. The country’s total gas production collapsed to a mere 28mn m³/d in April, before rebounding somewhat to 35mn m³/d in May, based on data from the national institute of statistics. Prices for Bolivian gas are down over two-thirds, reflecting the collapse in oil prices.

VOL 5, ISSUE 16 | 31 AUGUST 2020

Source: US Energy Information Administration; BP Statistical Review of World Energy

Fig. 1 — Bolivian Dry Gas Production and Consumption (mn m³/d)

Production

Consumption

70 60 50 40 30 20 10

20 18

20 16

20 14

20 12

20 10

20 08

20 06

20 04

20 02

20 00

19 98

19 96

19 94

19 92

19 90

19 88

19 86

19 84

19 82

19 80

0

Source: BP Statistical Review of World Energy

Fig. 2 — Bolivian Proved Gas Reserves (bn m3)

350 300 250 200 150 100 50

Sales to Argentina and Brazil, the two export markets for Bolivian gas, are increasingly under threat from rising domestic gas production – shale gas from the Vaca Muerta and conventional gas from sub-salt fields, respectively – and relatively and increasingly cheap LNG. When the Bolivian government signed long-term gas export contracts with Brazil in 1999 and Argentina in 2006 and linked their landlocked country to its neighbours with pipelines, gas was a relatively scarce and expensive fuel.

Argentina is now itself an LNG exporter.

At the same time, Bolivia’s efforts to open new export markets for its gas were moving slowly even before recent political

19

20 18

20 16

20 14

20 12

20 10

20 08

20 06

20 04

20 02

20 00

19 98

19 96

19 94

19 92

19 90

19 88

19 86

19 84

19 82

19 80

0

events stalled them. The interim government ruling the country since last November, led by Jeanine Anez, lacks the legitimacy and political support to negotiate the necessary deals. Despite promising new national elections within three months, her government has postponed them three times, leading to mass street demonstrations and blockades across the Andean country.

Bolivia has had talks with Paraguay to build a gas pipeline between the two countries, and also with Argentina and Peru to export gas to international markets using the liquefaction plants in their countries. La Paz had hoped to build an LNG plant on the northern coast of Chile, but this was blocked by an October

Bleak future for Bolivian gas

2018 ruling by the UN’s International Court of Justice against its longstanding claim for sovereign access through its western neighbour. Bolivia lost its coastal provinces in a war with Chile in the late 19th century.

It was reported in mid-August that Argentina is to launch yet another price support programme for gas in the near future, with guaranteed prices for producers of around $3.40/mn Btu for the next four years.

ESTABLISHED MARKETS

OTHER MARKETS

Since peaking at a combined 45mn m³/d in 2014, according to BP Statistical Review of World Energy data, by 2019 Bolivia’s gas exports to Argentina had declined by 9% to 13mn m³/d and to Brazil by a whopping 42% to 15mn m³/d. These declines are reflected by changes in contracted gas volumes from Bolivia being renegotiated downward in recent years by both Argentina and Brazil.

In mid-June, YPFB accepted a request by Brazil’s state-controlled Petrobras to lower its minimum imports of Bolivian gas to just 10mn m³/d. “In light of the extraordinary situation we face, we approved the force majeure requested by Petrobras because of Covid-19,” YPFB said in a note.

The original long-term contract called for Petrobras to import a minimum of 24mn m³/d and a maximum of 30mn m³/d, with the minimum cut to 14mn m³/d as recently as March. The contract was to expire in 2019 but has been extended because over its 20-year term, Petrobras has often taken less than it has contracted.

Argentina’s state-run Enarsa successfully renegotiated its long-term gas contract with Bolivia in February 2019, with deliveries slashed to 11mn m³/d in the summer months of October through April and 16-18mn m³/d during the colder months, when consumption surges for heating purposes. Contracted volumes were supposed to average 20mn m³/d through 2026.

Brazil’s imports of Bolivian gas are likely to continue to decline substantially more than Argentina’s in a relatively low-price post-Covid world, given the relatively high cost of developing Vaca Muerta shale compared with its own off-shore sub-salt resource.

On that note, Petrobras is maintaining its 2020 target of 2.7mn barrels of oil equivalent (boe)/d for domestic oil and gas output, despite Covid-associated lockdowns hammering global oil and gas consumption and prices. The company produced 2.76mn boe/d in the second quarter, a decline of 3.5% compared with the first quarter but up 8% year-on-year. Domestic production overall for the first six months of the year averaged 2.81mn boe/d, an increase of almost 12% compared to the same period in 2019.

In contrast, the Argentine government is attempting to revive activity in Vaca Muerta after a total collapse earlier this year. The number of fracking stages in the region was zero in April, compared with 430 in March. The number of active oil and gas rigs in Argentina as a whole has declined from around 60 in the first half of 2019 – before the country’s latest debt crisis and Covid – to no operating rigs now. According to Argentina’s energy secretariat, domestic gas production declined by 10% year-on-year to 126mn m³/d in June.

With gas exports to Argentina and especially Brazil in decline, the Bolivian government had been negotiating to export gas by pipeline to Paraguay and via LNG liquefaction plants on the coasts of Argentina and Peru for overseas markets.

In November 2018, Bolivia’s minister for hydrocarbons Luis Alberto Sanchez and Paraguay’s minister for public works Arnoldo Wiens signed a memorandum of understanding on building a gas pipeline between the neighbouring land-locked countries. “Talks are very advanced and we have spoken with the outgoing and incoming presidents about the project,” said Morales at the time. The two governments agreed to a final design study in June 2019, but the project has since stalled with the political situation in La Paz. The same can be said for potential LNG export facilities in Argentina and Peru, with both showing progress until the ouster and self-imposed exile of Morales last November.

At a news conference in Buenos Aires in April 2019, Morales and his Argentine counterpart, Mauricio Macri, announced plans to widen energy integration between their two countries, including construction of liquefaction terminals on Argentina’s coast to export Bolivia’s gas. These projects would benefit from existing pipelines, as Argentina’s need for Bolivian gas continues to decline, and joint financing by Argentina’s state-controlled YPF SA and YPFB. In January 2019, the energy ministers of Bolivia and Peru met to discuss construction of a gas pipeline and a liquefaction plant to export LNG to Asia, with detailed engineering of the gas pipeline already underway. “We’re interested in investing in Peru’s Ilo port,” Sanchez said after his meeting with counterpart Francisco Ismodes.

In 2018, Morales and the president of Peru Martin Vizcarra met three times to discuss bilateral relations, including Bolivia’s use of the Ilo port in southern Peru and building a liquefaction plant there to export its gas. There were grounds for optimism: in 1992, Peru granted Bolivia a 99-year lease over a 17.5-km stretch of coastline near Ilo for industrial and port development. In June 2015, Morales and the then president of Peru Ollanta Humala first agreed to study the Ilo gas pipeline and LNG project during a summit in Lima.

To conclude, a potential lack of markets, made worse by present political turmoil, pose serious impediments to Bolivia’s efforts to attract investment and exploration activity by international oil companies.

20

Bleak future for Bolivian gas

COLOMBIA EYES

SECOND TERMINAL As its own gas runs out faster than new finds may be brought on stream, the South American country is being pushed toward building a second LNG terminal.

Kenna Bravo

In its efforts to avoid what could an imminent gas crisis, the Colombian government has rediscovered its enthusiasm for its Pacific LNG importing terminal. The project could offset the domestic gas deficit, as natural gas reserves dwindle in the country.

On June 30, the energy mining and planning unit (UPME, the part of the mining and energy ministry responsible for infrastructure planning), relaunched a bidding process to design, construct and operate a new LNG facility and a pipeline in Buenaventura, on the Colombian Pacific Coast.

The South American country commissioned its first LNG terminal on its Caribbean coast in December 2016. It is a floating storage and regasification unit (FSRU) located in Baru, Cartagena de Indias. With 400mn ft³ /d (8.5bn m³/yr) of regasification capacity and 170,000 m³ storage capacity, the FSRU, operated

by Sociedad Portuaria El Cayao (SPEC GNL), supplies regasified LNG to three thermal power stations in Colombia.

21

Although two thirds of the national power generation mix is hydro, the country’s rainfall is not as dependable as it once was, and its gas reserves are in decline. The government is therefore looking at more LNG in a new part of the country.

But the plan is not popular everywhere: its opponents say that if more gas is needed, the government should prioritise domestic production instead of buying what may become expensive imports.

LOOMING GAS SHORTAGE According to official figures, Colombian proven gas reserves will last for about eight years but as they taper off, shortages will be possible by 2024, affecting power generation and industrial demand.

VOL 5, ISSUE 16 | 31 AUGUST 2020

Fig. 1 — Colombia’s gas reserves

Source: ANH

12

18 Proven

Probable

Possible

Reserves to production ratio 16

13,6

13,9 13,4

14 12,1

7.058

7.008 6.630

489 bn ft3

515 6

11,7

11,3

8

1.162

652

759 523

12 10,5

10,3 9,8

6.408 394 507

10

5.915 5.443

290

422

866

659

5.321

5.206

522

457

775

853

4

5.406

5.463

5.727

4.961 410 769

5.508 4.759

2

8

Reserves to production ratio (in years)

10

6

4 4.361

4.024

3.896

3.782 2

0

2010

2011

2012

2013

Under this scenario, UPME has concluded that to secure the natural gas supply and its reliability as a public service over the next 10 years, the Colombian system will need to reinforce the midstream infrastructure by including an importing facility and new pipeline for natural gas transportation on the Pacific coast.

PACIFIC LNG IMPORT TERMINAL An LNG regasification terminal in Buenaventura in the southwest and a 30-in pipeline around 100 km long, will cost about $700mn.

Though the primary purpose of the new facility is to offset a gas shortfall in the coming years, it has gained some detractors in the local industry who claim that the Colombian government has not given priority or support to local gas producers to develop national reserves.

NGW discussed the benefits associated with new LNG infrastructure with lawyer Monica Torres, the CEO of Viable Legal Business. She was one of the lawyers involved in the bidding process for the Cartagena terminal.

22

2014

2015

2016

2017

2018

Some studies have claimed that there are important conventional and unconventional gas resources both on and offshore, which has opened the debate in the local gas industry over the real need for a new importing facility.

However, as Torres explained, a gas shortage crisis is expected in the short-term, while it takes some time to bring new discoveries to market, so time is of the essence. Even though the Colombian government started assigning exploration contracts last year, it could take at least six years for gas to reach the market – or seven in the case of offshore reserves. Unconventional gas production using hydraulic fracturing remains prohibited.

DELAYS IN THE PACIFIC LNG TERMINAL Since 2018, the Colombian government has seen the Pacific terminal as an alternative to avert the gas shortfall. But as Torres explained, the first element has been based on expectations over the potential increase in natural gas domestic production.

Expectations have and continue to hold back the project, she added. Even though domestic natural production could potentially

Colombia eyes second terminal

In terms of jobs, it is expected that during the phases of constructing, operating, and maintaining, the new terminal will benefit the economy of southwestern Colombia.

increase in the future, Colombia cannot afford to wait in the short term. The LNG import infrastructure in the Colombian Pacific has more than two years’ delay and this delay has been due to those expectations, she said.

The second factor of delay perhaps has been to set a new regulation, she indicated. Torres stressed that for the Pacific LNG terminal, the Colombian government has had to establish a commercial and legal framework completely different from the Caribbean terminal.

She explained that the Cartagena regasification project emerged as a solution to fuel supply problems for the three thermal plants in the Colombian Caribbean, and the main driver was to replace expensive and polluting liquid fuels such as diesel with gas. The Pacific infrastructure, on the other hand, is intended to promote new sources of gas in the country, as reserves will not be sufficient to secure the constantly growing demand.

BENEFITS, OPPORTUNITIES, AND CHALLENGES OF THE NEW TERMINAL Torres highlighted that the Pacific terminal is considered a public interest project, which means it enjoys different regulations and tariffs than the Caribbean terminal.

The new terminal will not only consider national gas demand but also will aim to meet its continuing growth, supporting power generation in periods when hydroelectricity output is not sufficient and create new supply for industries and local communities, which now have access only to the most expensive natural gas in the country.

Besides, with the LNG regasification terminal operating, there is the opportunity to distribute gas by truck, reaching a higher number of users who today do not have access to natural gas, she added.

23

In terms of jobs, it is expected that during the phases of constructing, operating, and maintaining, the new terminal will benefit the economy of southwestern Colombia.

Investors will receive a regulated income, which will be paid mainly by regulated demand (small consumers) through the natural gas service rate, Torres said. There is a draft resolution under which the regulator has proposed a mechanism to alleviate the payment burden that otherwise would fall on small consumers, and gives access to the competitive market, such as power generators and industry. They might also receive contracts granting access to the terminal, helping to underpin the costs.

However, Torres mentioned that the project could also face some environmental challenges. The area in which the project would take place not only involves protected areas for environmental reasons but involves indigenous territories and ethnic groups and probably some difficulties due to the terrain.

To start the building phase, the bidder must have an environmental licence, issued by the environment regulator. Moreover, if the pipeline route affects the enjoyment by the indigenous people of their land, the bidder must go through a consultation process that will ensure the protection of those groups’ fundamental rights.

So there is no guarantee that an environmental licence will be granted and in any case it could force a delay to the planned date for starting operations.

According to the new timetable, which expects to see commercial operations of the project in 2024, the deadline to release the final bidding documents was scheduled on July 30. But as the health crisis has hit the country, the documents have not yet been released.

Torres said that there are many investors interested in the project and this is a positive indication concerning the bidding process.

It is due to start in the first quarter of next year, according to the authorities’ announcement.

Colombia eyes second terminal

GAME- CHANGERS FOR

US-MEXICO GAS Gas flows from the US to Mexico are at record highs, and some of this gas could soon be shipped on elsewhere in the form of LNG. Anna Kachkova

Gas trade between the US and Mexico is evolving as new infrastructure continues to come online. While the Covid-19 pandemic has proved to be a setback – as it has elsewhere – on the whole the gas trade has stayed relatively resilient and flows from the US to Mexico have reached record highs. The trend is set to continue with further pipeline capacity additions on their way, driven in large part by growing gas demand from power generation plants in Mexico.

A further significant development in the US-Mexico gas trade picture will be the liquefaction of US-sourced gas on northern Mexico’s Pacific Coast for onward shipment to Asian markets.

23

The plan, being developed by US-based Sempra Energy, has various hurdles to overcome before it can be realised, but there is relatively high confidence that it will come to fruition.

RECORD HIGHS The gas trade between the US and Mexico received a major boost last year with the start-up of the Sur de Texas-Tuxpan pipeline in September 2019. The 800-km pipeline runs almost entirely under the Gulf of Mexico, from South Texas to the Port of Tuxpan in Mexico. The pipeline has a capacity of 2.6bn ft³/d,

VOL 5, ISSUE 16 | 31 AUGUST 2020

Tuxpan pipeline supply impact

Source: S&P Global Platts

and its start-up increased Mexico’s natural gas import capacity by 40% – allowing it to take advantage of low-cost US gas supplies.

This has gone some way towards displacing Mexican demand for LNG imports, notably at the Altamira terminal on the country’s Gulf Coast.

“That was a big moment for the Mexican gas market because in short, it meant a shift in the primary sources for the eastern and northeastern regions,” a Mexico gas analyst at Genscape, Ricardo Falcon, told NGW. “With [Mexican utility] CFE being a major offtaker, this was a big move towards a more dynamic Mexican Gulf corridor in terms of pipeline infrastructure,” he said.

More pipeline infrastructure linking the US and Mexico has followed, though like the Sur de Texas-Tuxpan project, other projects have also suffered delays.

Falcon said that most of the pipelines had not come on line as expected for structural, non-technical challenges or other risks, and not just because of Covid-19.

Given its far-reaching impact, including on energy projects, it is not surprising that Covid-19 caused a drop in gas flows from the US to Mexico earlier this year. Independent Commodity Intelligence Services (Icis) estimates that US-Mexico pipeline flows dropped by around 1.5bn ft3/d from late March to mid-April, from a peak of near 5.9bn ft3/d to a low of around 4.4bn ft3/d.

However, flows have been quick to rebound, and RBN Energy analyst Jason Ferguson told NGW that US exports to Mexico had recently risen above 6.3bn ft3/d, which he noted was a new record. “August exports are up 0.5bn ft3/d versus last year,” he said. “It does appear there was an impact from Covid19 earlier this year, as year-to-date exports are up only 0.175bn ft3/d.”

24

Despite this setback, however, gas trade between the two countries continues to expand. And a further increase in cross-border gas flows is expected when the final section of the Wahalajara system goes into service. The northern Tarahumara pipeline segment is already online and delivering gas from the Permian Basin into Mexico. Meanwhile, start-up of the southern Villa de Reyes-Aguascalientes-Guadalajara (VAG) segment has been delayed, even though construction on the pipeline was completed earlier this year. The delay has been attributed to a dispute between anchor customer CFE and pipeline builder Fermaca, with no news as yet on its resolution.

Once the VAG segment is online, gas will be able to travel all the way from the Waha Hub in Texas to Guadalajara, potentially displacing LNG imports at the Manzanillo terminal on Mexico’s Pacific Coast.

James Fowler, Americas energy market development manager for Icis, told NGW that depending on when the final segment comes online, he would expect cross-border gas flows to rise by at least 300-400mn ft3/d. “The idea would be that once you have the Wahalajara pipeline completed, you’d be able to replace LNG imports with the gas pipeline imports from the US,” he said.

Genscape, for its part, also considers the start-up of the system in full to be significant. “Once Wahalajara comes online, which is something we believe could happen this year, that could be another change of the game,” Falcon said. He warned, however, that there was a downside risk. “The longer Wahalajara’s lower leg takes to come online this year, the less impactful it may be,” he said, explaining that a delayed start-up would face off potentially lower demand from both power generation and the industrial sector during the colder season in particular.

NEXT STEP There is also potential for yet another game-changing development for US-Mexico gas flows – the liquefaction and export of US-sourced gas from Mexico – in the not-too-distant future.

Sempra is proposing to convert an existing LNG import terminal on the Pacific Coast in Baja California to liquefaction under its Energia Costa Azul project. However, in the wake of Covid-19’s impact on the global LNG market, the company has postponed its final investment decision (FID) on the project, with a deadline for this now uncertain, having previously been pegged for the second quarter of 2020. Start-up had been scheduled for 2023 before the latest delay.

Sempra’s Mexican unit, IEnova, also still requires an export permit for Energia Costa Azul. However, Reuters reported in late August, citing sources familiar with the matter, that the Mexican government had asked IEnova to commit to another LNG export facility in the Port of Topolobampo before it would issue the export permit.

Sempra told NGW that it continued to “work closely with local authorities as well as the highest levels of the Mexican government on advancing the permit process”. The company said that as it had offtake and engineering, procurement and construction (EPC) contracts in place, it was ready to move forward with an FID subject to receiving the export permit.

 Game- changers for US-MEXICO GAS

Falcon noted that a government push to secure a commitment to the Topolobampo export project was not surprising, if it was true, and would not be the first time a similar initiative had been put forward. “The reality is that you see this almost every year, and that’s just because the government realises that at some point it over-contracted capacity to secure supply to major combined cycle power plants,” he said. “Of course, demand dynamics change and with Covid-19 that was more evident.

What they’re trying to do is just to work around that market reality and find new outlets to eventually send gas out of Mexico.”

Fowler noted that as well as being considerably less advanced than the Energia Costa Azul plan, a new facility at Topolobampo would be harder to justify given the cost of a greenfield development and the recent collapse of LNG prices amid a global oversupply.

“It would seem to me that that it’s a harder sell than the Baja project, it’s more difficult to get developed than the Baja project, just because of the way the global market is and the cost that would be associated with it,” he said.

There is a good deal more confidence, meanwhile, that Energia Costa Azul will go ahead, he said: it is “just a matter of time… it obeys different incentives. In this case, it will be more of an integration of a market that is more mature, I would say, and I’m referring to the upper part of Baja California.”

25

“ It would seem to me that that [Topolobampo is] a harder sell than the Baja project, it’s more difficult to get developed than the Baja project, just because of the way the global market is and the cost that would be associated with it.”

— JAMES FOWLER, ICIS

 Game- changers for US-MEXICO GAS

EUROPE TACKLES METHANE EMISSIONS

Europe’s reliance on natural gas imports creates a conundrum: gas is essential for the energy transition but its environmental impact is largely outside the bloc.

Caroline Gentry The natural gas industry has come under fire after revelations of increased flaring and large leaks undermine its claims to be a clean transition fuel. But most of the emissions occur upstream, outside Europe. The European Commission (EC) is working on how to address the international angle in its methane emissions strategy, which should be revealed in September.

“The EC presented its vision of a European Green Deal for the European Union and its citizens on 11 December 2019, which includes addressing the issue of energy-related methane emissions. The 2018 Energy Union Governance Regulation calls on the EC to deliver a strategic plan for methane and the energy sector could significantly contribute to it,” said a spokesperson.

Comments on a proposed roadmap were due by August 5 and are published on the EC website. As well as setting standards for monitoring, reporting and verification (MRV) and

26

leak detection, the strategy is likely to include only soft measures for voluntary collaboration at an international level rather than a mandatory methane supply index, which will fall short of what is required and technically feasible, says Poppy Kalesi from the Environmental Defense Fund (EDF).

EDF is working on a study of 16 different options for a methane emission import standard, such as including methane in the emissions trading scheme (ETS) and a fee on imports, which should be released in December. Options include price-oriented mechanisms such as penalties; a border adjustment tax or amendment to gas taxes based on climate effect; regulation such as a procurement standard; or a volume-oriented mechanism such as cap and trade or other tradeable quota system.

A procurement standard could incentivise a reduction in methane emissions intensity of imported gas in the form of tax

VOL 5, ISSUE 16 | 31 AUGUST 2020

Fig. 1 — Extra EU-27 imports of natural gas from main trading partners, 2019

5.7% 4%

Source: Eurostat database (Comext) and Eurostat estimates

4.5% 5.1% 7.2%

10.6%

38.3%

24.5%

Russia

United States

Nigeria

Qatar

Algeria

MADE TO MEASURE

United Kingdom Norway

Others

benefits or penalties for the buyers for non-compliant purchases.

The EC prefers some sort of market-based certification scheme, says Kalesi, but other than for aviation and shipping it is not yet feasible for energy-industry methane emissions to be covered by the existing European emissions trading scheme (ETS).

The International Standards Authority is working on an LNG label, initially covering emissions during liquefaction and addressing gas production and shipping subsequently. A working group will meet in September to discuss how to classify the LNG plant according to its carbon footprint under a low carbon LNG certificate.

An industry group – including the biggest European producers BP, Eni, Equinor, Repsol, Shell, Total and Wintershall Dea together with EDF, the Florence School of Regulation and the Rocky Mountain Institute – recommends a methane intensity-based performance standard of less than 0.20% for the upstream supply chain from 2025.

This is slightly more stringent than voluntary measures such as the Oil and Gas Climate Initiative (OGCI)’s initial carbon intensity target, of 20-21 kg CO2e/kg barrels of oil equivalent by 2025, or 0.25% methane intensity. OGCI includes many of the companies listed above, such as Total, which has set an even more ambitious methane intensity target of 0.1% for its operated upstream gas facilities.

Another proposal submitted in comments by the Austrian national regulator E-Control is to create a mandatory framework for transmission system operators based on a threshhold set by

27

the best available technology as predefined by a technical body.

European companies have already taken voluntary steps to reduce their own emissions, aligned with the Methane Guiding Principles Best Practice Guides and the US Natural Gas STAR Program Recommended Technologies to Reduce Methane Emissions. More than 20 European companies and 14 supporting organisations have signed on to the Methane Guiding Principles, a commitment to manage methane emissions along the gas value chain. Gas Infrastructure Europe and Marcogaz have continued to raise awareness of this topic and identify concrete action points, create guidelines to help companies set reduction targets, make methane policy recommendations, reconcile topdown and bottom-up best practises for measuring, reporting and verification and devise a reporting template.

OGCI’s Climate Investments fund has an open call for methane reduction projects that closes September 14. Power generation companies are already embarking on goals to reach climate neutrality by decarbonising their gas-fired power plants and storage facilities. The German utility Uniper has partnered with General Electric to develop technology options for decarbonisation involving potential upgrades and using more hydrogen.

Less than a quarter of the methane emissions from natural gas consumed in the EU occurs within its borders, according to Carbon Limits, a consultancy. Around 80% of the EU’s natural gas is imported, mainly from Russia, Norway, Algeria, Qatar and Nigeria. Until now methane emissions from flaring, venting and leaks have been mostly self-reported and/or estimated.

Emissions intensity varies widely and until recently it was hard to tell whether companies were accurately reporting emissions, especially during large leaks or unplanned venting. But that is about to change.

Recent developments in satellite technology combined with enhanced data interpretation techniques have paved the way for the creation of a more robust international framework for the detection, monitoring, reporting and verification of methane emissions across the full value chain of natural gas. This will make it easier to account for upstream emissions from the natural gas supply chain, not just for more visible flaring. Producers will face increased scrutiny for accidental leaks and intentional venting, that will present a competitive advantage for early adopters of emission cutting upgrades and penalise persistent heavy emitters.

OGCI will spend nearly $1mn on a publicly available online tool to map gas flaring data, working with the Payne Institute for Public Policy at Colorado School of Mines as part of the Global Gas Flaring Reduction Partnership (GGFR) led by the World Bank.

It will use the Visible Infrared Imaging Radiometer Suite (VIIRS) satellite and will be available in 2022.

A coalition of non-profits and technology companies has developed a monitoring solution using artificial intelligence and satellite image processing that received high profile attention thanks to the patronage of the former US vice president Al Gore.

Europe tackles methane emissions

The first version of ‘Climate Trace’ (another acronym, standing for Tracking Real-time Atmospheric Carbon Emissions) could be released as early as next summer. And there are many similar initiatives, such as Canada’s GHGSat which recently assembled its third satellite, part of a programme to put 10 greenhouse gas emissions monitoring satellites into orbit within the next two years.

French company Karryos, based on Sentinel-5P images from the European Union’s Copernicus network, estimates there almost 1bn metric tons of CO2e near-term mitigation potential.

“Eliminating methane ‘super-emitters’ is the low-hanging fruit of climate action, but market participants need both greater actionable information and regulatory certainty,” Karryos said in comments to the EC consultation.

While many energy companies pointed out in their comments to the consultation that the agricultural sector is a considerable contributor to methane emissions, “It’s not a question of either, it’s a question of and,” said Stephanie Saunier from Carbon Limits. Aside from the inevitability of legislation next year, when the EU will issue its gas market reform, cutting methane emissions makes good business sense.

Almost 300bn m³ of gas or 7% of consumption is wasted globally by flaring, venting and leaks, leading to a revenue potential loss of $34bn, according to consultants Capterio. But perhaps even more important is the reputational damage that may be wrought by ignoring growing pressure to come clean.

Companies such as Shell and Abu Dhabi state producer Adnoc are already delivering cargoes to Japan, South Korea and Taiwan offset with carbon emission reductions. And Pavilion Energy of Singapore issued a request for proposals for long-term LNG including a commitment to jointly develop an emissions quantification and reporting methodology.

Even national oil companies from traditionally climate-ambivalent countries such as in the former Soviet Union and Africa are starting to wake up to this new reality. The public image and therefore the future of the natural gas sector in the coming decades, as well as the growing blue hydrogen industry, will depend very much on how it tackles the methane emissions problem.

28

EU PREPARES EMISSIONS STRATEGY The European Commission is due to come up with ways to limit anthropogenic methane emissions, less than a fifth of which come from energy. Agriculture and waste are each bigger contributors. The Green Deal and the Paris Agreement are both pushing the EU towards climate-neutrality, where any remaining greenhouse gas emissions are offset by carbon abatement such as carbon sinks.

Some estimates show that external carbon or methane emissions associated with EU natural gas consumption are between three and eight times the number of emissions occurring within the EU. Further, external emissions are not evenly distributed with the bulk of the emissions coming from a very small proportion. So eliminating these would be relatively big gains.

Within the EU, infrastructure operators are regulated and do not own the molecules that are leaking from import terminals and pipelines. This suggests that national regulators will have to find a find a way of incorporating leak detection and repair activity as part of their allowed costs.

The first problem facing the EU is to set emissions measurement standards: there is likely to be an incentive to under-report. The United Nations Framework Convention on Climate Change has a three-tier reporting framework for methane emissions, which might form the basis of such a system, although there is no consistency between member states. Tier 1 is the crudest, involving simple estimates while Tier 3 requires individual measurements. Very few countries are in this group.

The EU will probably work with other organisations such as the World Bank, which regularly reports on flaring based on satellite imaging, and has a Zero Routine Flaring initiative.

On the ground, a harmonised policy for encouraging biogas could encourage technology that reduces methane emissions while providing renewable energy, converting waste streams into cash for farmers.

The EU could offer technical assistance on methane regulatory frameworks and monitoring, reporting and verification capacity but it can also learn from countries with methane-reduction targets. Other big exporters, such as Russia, could also become involved, if they want to keep selling their gas. But not all Gazprom’s exports flow through EU pipelines: some also go through Belarus or Ukraine.

The EU could also work together with other big importers such as South Korea and Japan to bring pressure to bear on exporters to implement methane reporting and verification standards, which in turn would make emissions reduction technologies more attractive investments.

-NGW

Europe tackles methane emissions

NATURAL GAS WORLD

EDITOR IN CHIEF

ASIA EDITOR

AMERICAS EDITOR

William Powell

Shardul Sharma

Dale Lunan

EDITOR, LNG

FEATURES EDITOR

EDITOR

Charles Ellinas

Joseph Murphy

CONDENSED Ross McCracken

H. Rick Gill

If you have any enquiries regarding advertising, events or past or future content, please contact: EDITORIAL

ADVISORY BOARD

William Powell – william.powell@naturalgasworld.com

Rune Bjørnson; Thierry Bros; Jean-Arnold

EVENTS & ADVERTISING

MANAGING DIRECTOR

Vinois; Jupiter Ramirez; Tatiana Mitrova

Joao Salviano – joao.salviano@naturalgasworld.com PRODUCTION & LAYOUT Blunt Strategic – info@bluntstrategic.com

REGULAR CONTRIBUTORS Dalga Khatinoglu, Ilham Shaban (Baku); Linas Jegelevicius (Vilnius); Omono Okonkwu (Lagos); Andrew Kemp; David O’Byrne (Istanbul); Anna Kachkova; Dmitri Shlapentokh (South Bend); Jeremy Bowden (Exeter); Alex Forbes (Brighton); Tim Gosling (Prague), Andreas Walstad (London) PUBLISHED UNDER LICENCE BY Minoils Media Ltd. 1000 Cathedral Place 925 West Georgia Street Vancouver, B.C. Canada V6C 3L2 © Copyright 2019 – All rights reserved. Reproduction of the contents of this magazine in any form is prohibited unless with the written consent of the publisher. Subscription packages for Natural Gas World range from a private individual to any agreed number of readers within a company. Subscriptions include email notification of the latest issue, allowing it to be downloaded by as many individuals as the package covers. A package makes it easier to avoid copyright infringement as single-user licences do not cover the distribiution of the contents to third parties.