Condensate is a Natural Gas Liquid (NGL) and so a by-product of gas production. In recent years it has moved from a niche activity, dominated by a handful of Mideast Gulf exporters and Asian buyers, into the mainstream of East of Suez trade.

Condensate either precipitates naturally out of gas flow (wellhead, or field condensate) or is stripped from gas (plant condensate), which are often combined in Mideast condensate grades. It therefore parallels and follows gas field development and gas production. Unlike other NGLs ethane and LPG (listing usually lightest to heaviest, as heaviest of all needs no containment) it needs no special containment; once it becomes a liquid, it remains a liquid. Condensate is light, normally above API 50°, low in sulfur (sweet) and usually produces more than 50% naphtha yield – a light, sweet crude equivalent, but not a crude oil grade. Condensate has many uses, leading to multiple, sometimes contradictory labels and a wide range of valuation.

Two supply trends will shape the rest of the decade. The Mideast Gulf will reach its production plateau for segregated condensate output by 2016, and if the need for domestic gasoline and petrochemical feedstock continues to rapidly grow, then exports may see significant volume decline. On the other side of the ledger, the US is emerging as a major NGL exporter, supported by fast-expanding shale gas output. American condensate exports will reshape Asia Pacific markets by 2020.


All other factors being equal, higher-value wet gas, containing as it does a high percentage of NGLs, but in particular condensate, is developed before dry gas. Increasingly the prospective condensate take is a key factor in supporting the high costs of developing Liquefied Natural Gas (LNG) projects. Indeed, NGL revenues have become a key support for most gas developments, particularly in the Mideast Gulf where gas is sold to the home market at low prices, and thus the key scope for turning a profit depends on the higher-value liquids output.

Asia Pacific will continue to lead world oil demand growth. That rate of growth will slow down to strong, but more moderate levels, perhaps 3% per year by mid-decade, as developing country economies mature and retail subsidies are gradually cut. The Mideast Gulf, a much smaller sub-region, will continue to record strong growth in gasoline demand, under price controls that severely undervalue both gas and condensate. As Gulf exporters run out of ethane and LPG to supply the expansion of base petrochemical capacity, they may have to increasingly rely on condensate to fill the gap.

Tables included East of Suez Segregated Condensate Supply Outlook - Base Case (MN B/D)

2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022
MIDEAST GULF 2,316 2,490 2,706 2,978 3,169 3,306 3,404 3,562 3,660 3,882 3,992
Qatar 687 693 695 717 757 791 789 839 882 985 1,105
Saudi Arabia 660 737 870 970 1,000 1,010 1,045 1,080 1,110 1,120 1,086
Iran 518 570 614 712 780 815 843 887 929 1,021 1,065
UAE 429 456 488 516 535 558 566 569 552 549 529
Iraq 21 33 38 60 90 121 142 160 160 176 176
Oman 1 1 1 3 7 11 19 27 27 31 31
ASIA PACIFIC 856 919 978 1,011 1,089 1,175 1,290 1,331 1,340 1,373 1,378
Australia 139 145 159 185 185 245 339 353 358 392 410
China 170 186 195 196 216 240 253 262 268 273 280
Indonesia 170 173 191 185 187 188 191 201 197 199 188
Malaysia 99 101 106 109 127 130 133 138 133 136 135
Thailand 64 80 93 100 104 100 96 93 87 82 78
other Asia-Pacific 213 234 234 236 270 272 278 284 296 290 287
TOTAL 3,172 3,409 3,684 3,989 4,258 4,481 4,694 4,893 5,000 5,255 5,370


A continuing slow recovery of the Atlantic Basin from the recession of 2008 has condensate trade and demand shifting to East of Suez markets. The trend accelerated in 2013, and we expect it to continue through the decade. Splitters have remained the chief consumer of segregated condensate and their share of condensate utilization has grown further in recent years, making up the bulk of Asia-Pacific condensate use. Our past estimates of Asia Pacific condensate demand did not include refinery utilization and condensate sold as naphtha. Including these, demand in 2012 topped 1.7mn b/d.

Yet the focus of condensate production in the near term remains the Mideast Gulf: Saudi Arabia’s efforts to develop its substantial non-associated gas potential have been a major theme of upstream efforts.


The Kingdom needs a sustained expansion of gas production, in order to meet ballooning power needs. Parallel to this, Riyadh must produce more NGLs to supply feedstock to its still expanding base petrochemical sector. Most incremental condensate output will come as a by-product of associated gas in oil project developments. Yet Aramco’s recent turn to non-associated gas projects will make these new projects even more dependent on NGL revenue. All Mideast countries are suffering a shortage of gas output, in part because of unrealistically low prices for gas.

The ‘Goldilocks Dilemma’ can be seen most clearly in Saudi gas policy. The Kingdom must raise the price of gas and NGLs to encourage companies to look for and develop new non-associated wet gas reserves and lessen its dependence on associated gas; yet to attract further large-scale petrochemical and refinery investment, it must keep long-term feedstock prices low. The UAE, Kuwait and Oman have been struggling with the same problem – only Oman has begun to consider seriously a gradual rise in gas and condensate prices to pay for expanded gas output.

Other than Qatar, all Mideast condensate producers will attempt to restrain exports, by utilizing output in the domestic market first – even if the net result is only increased naphtha sales abroad. Saudi Arabia’s overall condensate policy is typical. The Kingdom uses condensate as trim feedstock to supply expanded olefin capacity, restrains Khuff grade exports to maintain premiums for A-180 sales, and, when international crude supply/demand balances become tight, spikes it to flesh out black oil production. The Kingdom’s oil production is so large that uniquely it could spike its entire condensate output into the black oil pool with little impact on crude quality.


In Saudi Arabia, as in the rest of the Mideast Gulf, a substantial portion of naphtha exports come, directly or indirectly, from condensate. Qatar joined the Kingdom and UAE/Abu Dhabi in marketing a condensate as a naphtha grade. Indirectly, through splitting, condensate contributes substantially to overall Gulf naphtha production and exports. Direct-feed petrochemical condensate sold as naphtha, together with naphtha derived from condensate made up nearly half of Mideast Gulf sales in 2013. Kuwait may soon join the ‘condensate sold as naphtha’ club, as it has queried market interest.

Despite a supposedly fresh start under a new president, we see sanctions continuing to cripple Iranian gas development and handicapping condensate production, through the medium-term. Sanctions, a lack of funds and the disappearance of foreign investors have greatly slowed the startup of new splitting capacity and kept condensate output gains to a minimum. We expect that Iran will add further output throughout the decade, but at minimal pace and that new splitter capacity will start up, but much delayed from original plans.

Qatar has nearly completed its broad-based gas sector development, including a massive LNG program, the completion of the world’s first commercial-scale Gas-to-Liquids (GTL) project, and piped gas developments, both for export and the domestic market. This exporter must now determine its future direction as a condensate seller that has committed most if not all of its available exports. The long-awaited end to a moratorium on new projects has fallen back to 2016, and may slip further.


The Mideast Gulf faces a structural gas shortage, as most easy-to-develop reserves have already been exploited. Now the more cost-difficult projects have begun – developing offshore non-associated gas (Saudi Arabia), tight gas reserves (Oman), highly sour gas (UAE) and irregular and high-pressure reservoirs (Kuwait). Foreign partnerships will be vital. Of course, the largest potential supplies of incremental ‘easy gas’ remain in Iran and increasingly Iraq, but sanctions for the former and political violence for the latter make them longer-term prospects.


Asia Pacific too faces big decisions on condensate. Chief of these is a desire to move away from overdependence on Mideast Gulf naphtha exports. Feedstock flexibility has become the rallying cry of olefin companies, particularly in East Asia. Petrochemical naphtha buyers increasingly have been using alternative feedstocks, including condensate, LPG and ethane. We believe that these NGLs will play a growing role in petrochemical feedstock supply and that Asia Pacific will turn to other regions to reduce its traditional Mideast Gulf naphtha purchases. North American NGLs, derived from shale gas, will play a major role in this, as Canada joins the US as a major shale gas and NGL producer.

Other parallel trends are emerging. The problem of a light-end squeeze in key markets such as China has diminished, just as refiners have turned to buying condensate in large volumes as a light crude proxy, as well as to boost middle distillate output, particularly for jet/kerosene. The call on light-end outturn has Beijing planners worried, despite the continuing expansion of refining capacity there. In the second half of 2012, large refiners such as ExxonMobil, JX Nippon and SK Energy all became large-scale and regular Mideast condensate lifters.


Asia Pacific will see segregated condensate output rise by much smaller volumes through mid-decade. In the second half of the decade, Australia will dominate incremental condensate output. Smaller volume increases will be seen in Indonesia and Papua New Guinea (PNG). Many emerging condensate producers, such as PNG, Vietnam, Brunei, Myanmar and Bangladesh will be forced to export much of their condensate output, due to limited refining in their home markets.

Australia will not only become the source of most incremental condensate output for the region, but the spawning ground for two different LNG development approaches that will impact condensate. A series of Coal Bed Methane (CBM) developments in Queensland hope to prove that LNG without any NGL revenue can work. Such projects of course are totally dependent on future international gas prices. More important for condensate is the floating LNG concept under development by Shell and to first start up on the Prelude field, off Western Australia. The use of floating LNG (FLNG) tankers to produce ‘lonely gas’ from isolated finds boost condensate output substantially by developing discoveries distant from shore. We believe that four CBM projects have made progress, while others are planned.


Shale gas will begin to impact condensate balances no later than by 2016, as excess American supply flows west after filling Canadian diluent needs. Shale gas, unlike CBM, is a longer-term prospect, but substantial potential exists in China, and certainly some shale production also will emerge in Australia, and possibly in India and Indonesia. As shale gas development has shown in the US, parallel NGL output as well as crude oil production will emerge from these future projects.

The revamping of the Panama Canal, due by mid-2015, will vastly increase the competitiveness of NGL exports from the US Gulf, while allowing passage to all but the largest LNG tankers. LPG sales to Asia Pacific from the US have zoomed upward and we expect US Gulf exports – possible in cargoes of over 1mn barrels – to begin to impact Asian condensate balances and pricing by mid-decade.

Most condensate will continue to be processed by splitters. Total condensate processing capacity for East of Suez markets will reach nearly 3.3mn b/d by 2018, and this could yield up to 2.2mn b/d of naphtha and gasoline. Though a substantial part of that naphtha will be converted to gasoline, particularly in the Mideast Gulf, this represents an enormous volume of petrochemical feedstock. Asia Pacific will finally dominate splitting capacity, with its share of total East of Suez splitting rising from 46.8% to 51.2% (on slightly over 1.7mn b/d of a total of 3.3mn b/d). Many newly-commissioned Asian splitters will be cross-integrated with aromatic petrochemicals.


This is beginning to impact the relative value of paraffinic-oriented versus N+A (napthenes and aromatics)-oriented condensate grades. These aromatic complexes will produce the full range of products and feedstocks possible, moving in multiple markets. While absorbing the N+A end of naphtha outturn, many plants will have to dump their paraffinic naphtha production on a feedstock market already under stress. The paradox is that while the need for aromatics-oriented condensate will tend to push overall prices up, paraffinic grades will suffer from ever more paraffinic naphtha produced and exported by these complexes. An N+A premium will likely increase imports of African condensate.

Quality differentials have begun to characterize sales of condensate, particularly in the Mideast Gulf, where lower-quality Iranian grades have been severely discounted. Asia Pacific’s continued drive to higher quality products leaves new splitter projects little choice, but to include hydrotreating in their planned configurations.

We expect a number of anticipated new condensate grades to emerge by 2018, including new grades from Iraq, Myanmar, Indonesia, China, Australia and the US. They are a mixed bag, with some grades paraffinic-oriented and others N+A-oriented. Further imports from the US, Russia and Nigeria will introduce other new grades.

Condensate prices have diverged increasingly from crude since the recession of 2008 began. Petrochemical use of condensate often has been strong, when gasoline’s call on condensate has been weak. We expect naphtha prices to increasingly dominate condensate sales at least in the medium term, but the impact of middle distillates is growing as well as refiners’ influence in setting condensate price levels.


Oddly enough, the linkage of condensate pricing to crude marker Brent has moved to other condensate grades outside of Australia. The Thai-Malaysian Joint Development Authority’s (JDA) output is often sold on a Brent linkage, and Vietnam also has moved to sales based on Brent. When US exports hit the Asian market, it is likely some pricing component will come from Mont Belvieu NGL pricing, nearby Houston.

Both crude and naphtha traditionally have been used as pricing markers for condensate. The proliferation of new condensate grades and the very flexible nature of condensate in utilization have led to a proliferation of condensate pricing systems and markers. Increasing use of LPG in petrochemicals may well add another price marker for petrochemical condensate sales.

Trade patterns are in flux and the condensate marketing world of 2018 will look very different than today’s. While most are aware that Qatar’s sale of condensate will be a key factor in future trade patterns, fewer realize that new condensate supplies will emerge from the renovated Panama Canal and the development of the Russian Arctic Circle trade route, the Northeast Passage. There will be more players and more condensate grades on offer by mid-decade in a highly competitive market.

That point noted, the main source of condensate imports for Asian purchasers remains the Mideast Gulf. We do expect exports from the US, Russia and possibly West Africa and South America, to emerge as market factors though by 2018. We see condensate trade, marketing and use moving increasingly to an East of Suez focus, though growing volumes worldwide mean that condensate is fast-becoming a global trade.

*Al Troner is President of Asia Pacific Energy Consulting (APEC) This article presents the key findings of APEC’s latest study “Condensate East of Suez 2013”.